[Federal Register Volume 78, Number 60 (Thursday, March 28, 2013)]
[Rules and Regulations]
[Pages 18817-18837]
[FR Doc No: 2013-07113]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM12-4-000; Order No. 777]

Revisions to Reliability Standard for Transmission Vegetation
Management

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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SUMMARY: Under section 215 of the Federal Power Act (FPA), the Federal
Energy Regulatory Commission (Commission) approves Reliability Standard
FAC-003-2 (Transmission Vegetation Management), submitted to the
Commission for approval by the North American Electric Reliability
Corporation (NERC), the Commission-certified Electric Reliability
Organization. Reliability Standard FAC-003-2 expands the applicability
of the standard to include overhead transmission lines that are
operated below 200 kV, if they are either an element of an
Interconnection Reliability Operating Limit or an element of a Major
WECC Transfer Path. Reliability Standard FAC-003-2 incorporates a new
minimum annual inspection requirement, and incorporates new minimum
vegetation

clearance distances into the text of the standard.
    The Commission also approves the related definitions, violation
severity levels, implementation plan, and effective dates proposed by
NERC. The Commission approves the related violation risk factors,
except that it directs a revision to the violation risk factor
corresponding to one requirement.

DATES:  Effective Date: This rule will become effective May 28, 2013.

FOR FURTHER INFORMATION CONTACT:

Tom Bradish (Technical Information), Office of Electric Reliability,
Division of Reliability Standards, Federal Energy Regulatory
Commission, 1800 Dual Highway, Suite 201, Hagerstown, MD 21740,
Telephone:<PHONE_NUMBER>.
David O'Connor (Technical Information), Office of Electric Reliability,
Division of Reliability Standards, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426,Telephone: (202)
502-6695.
Jonathan First (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, Telephone:<PHONE_NUMBER>.
Julie Greenisen (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, Telephone:<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Final Rule

Issued March 21, 2013

    1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Commission approves Reliability Standard FAC-003-2 (Transmission
Vegetation Management), submitted by the North American Electric
Reliability Corporation (NERC), the Commission-certified Electric
Reliability Organization (ERO). Reliability Standard FAC-003-2 modifies
the currently-effective standard, FAC-003-1 (the ``Version 1''
standard). The proposed modifications, in part, respond to certain
Commission directives in Order No. 693, in which the Commission
approved FAC-003-1.\2\
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    \1\ 16 U.S.C. 824o (2006).
    \2\ See Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, FERC Stats. & Regs. ] 31,242, order on reh'g,
Order No. 693-A, 120 FERC ] 61,053 (2007).
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    2. Reliability Standard FAC-003-2 has a number of features that
make it an improvement over the Version 1 standard. For example, like
Version 1, FAC-003-2 applies to all overhead transmission lines
operated at or above 200 kV, but unlike Version 1, it explicitly
applies to any lower voltage overhead transmission line that is either
an element of an Interconnection Reliability Operating Limit (IROL) or
an element of a Major WECC Transfer Path.\3\ The Reliability Standard
also makes explicit a transmission owner's obligation to prevent an
encroachment into the minimum vegetation clearance distance (MVCD) for
a line subject to the standard, regardless of whether that encroachment
results in a sustained outage or fault.\4\ Also, for the first time,
FAC-003-2 requires transmission owners to annually inspect all
transmission lines subject to the standard and to complete 100 percent
of their annual vegetation work plan. The Reliability Standard also
incorporates the MVCDs into the text of the standard, and does not rely
on clearance distances from an outside reference, as is the case with
the Version 1 standard. We believe these beneficial provisions, and
others discussed below, support our approval of FAC-003-2.
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    \3\ NERC defines ``IROL'' as ``[a] System Operating Limit that,
if violated, could lead to instability, uncontrolled separation, or
Cascading outages that adversely impact the reliability of the Bulk
Electric System.'' NERC defines ``System Operating Limit'' as
``[t]he value (such as MW, MVar, Amperes, Frequency or Volts) that
satisfies the most limiting of the prescribed operating criteria for
a specified system configuration to ensure operation within
acceptable reliability criteria.'' See NERC Glossary of Terms Used
in Reliability Standards (NERC Glossary) at 26, 48. The Western
Electricity Coordinating Council (WECC) maintains a listing of Major
WECC Transfer Paths, available at http://www.wecc.biz/Standards/Development/WECC-0091/SharedDocuments/WECC-0091TableMajorPaths4-28-08.doc.
    \4\ See Reliability Standard FAC-003-2, Requirements R1 and R2,
subsection 1; see also Petition of the North American Electric
Reliability Corporation for Approval of Proposed Reliability
Standard FAC-003-2--Transmission Vegetation Management at 4, 6 (NERC
Petition). NERC proposes to define MVCD as ``the calculated minimum
distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating
voltages.'' Id. at 2.
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    3. A recurring cause in many blackouts has been vegetation-related
outages. In fact, one of the initiating causes of the 2003 Northeast
blackout was inadequate vegetation management practices that led to
tree contact.\5\ Further, NERC has identified a focus on preventing
non-random equipment outages such as those caused by vegetation as a
top priority that will most likely have a positive impact on Bulk-Power
System reliability.\6\ We also note that industry has made important
strides in reducing the instances of vegetation contact.\7\ We believe
that industry compliance with FAC-003-2, together with a continued
focus by industry on best practices for vegetation management, will
serve to enhance the reliability of the Bulk-Power System. While we
approve NERC's use of the Gallet equation to determine the minimum
vegetation clearance distances, we believe it is important that NERC
develop empirical evidence that either confirms assumptions used in
calculating the MVCD values based on the Gallet equation, or gives
reason to revisit the Reliability Standard. Accordingly, consistent
with the Notice of Proposed Rulemaking (NOPR) proposal, the Commission
directs that NERC conduct or contract testing to obtain empirical data
and submit a report to the Commission providing the results of the
testing.\8\
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    \5\ See U.S.-Canada Power System Outage Task Force, Final Report
on the August 14, 2003 Blackout in the United States and Canada:
Causes and Recommendations at 18, 57-64 (April 2004) (2003 Blackout
Report).
    \6\ See written remarks by Gerry Cauley, NERC's Chief Executive
Officer, for the November 29, 2011 Reliability Technical Conference
at 1, 4 and 5 (Docket No. AD12-1-000).
    \7\ See, e.g., NERC's Third Quarter 2012 Vegetation-Related
Transmission Outage Report at 6-7, available at http://www.nerc.com/files/Item%202%20-%20Third%20Quarter%20Vegetation%20Report.pdf.
    \8\ Revisions to Reliability Standard for Transmission
Vegetation Management, Notice of Proposed Rulemaking, 141 FERC ]
61,046 (Oct. 18, 2012).
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    4. We also approve the three new or revised definitions associated
with the proposed Reliability Standard for inclusion in the NERC
Glossary. Specifically, we approve the changes in the definition of
``Right-of-Way'' and ``Vegetation Inspection,'' as well as the addition
of the term ``Minimum Vegetation Clearance Distance (MVCD)'' as defined
in NERC's petition. We also approve NERC's implementation plan for FAC-
003-2.
    5. NERC has not adequately supported the proposed assignment of a
``medium'' Violation Risk Factor to Requirement R2, which pertains to
preventing vegetation encroachments into the MVCD of transmission lines
operated at 200 kV and above, but which are not part of an IROL or a
Major WECC Transfer Path. As discussed later, system events have
originated from non-IROL facilities. Accordingly, we adopt the NOPR
proposal and direct NERC to submit a modification, within 60 days of
the effective date of the Final Rule, assigning a ``high'' Violation
Risk Factor for Requirement R2.
    6. As discussed below, we also direct NERC to develop a means to
assure that IROLs are communicated to transmission owners.

I. Background

A. Section 215 of the FPA

    7. Section 215 of the FPA requires the Commission-certified ERO to
develop mandatory and enforceable Reliability Standards, subject to
Commission review and approval. Once approved, the Reliability
Standards may be enforced by the ERO subject to Commission oversight,
or by the Commission independently.\9\ Pursuant to the requirements of
FPA section 215, the Commission established a process to select and
certify an ERO \10\ and, subsequently, certified NERC as the ERO.\11\
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    \9\ See 16 U.S.C. 824o(e)(3).
    \10\ Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval, and
Enforcement of Electric Reliability Standards, Order No. 672, FERC
Stats. & Regs. ] 31,204, order on reh'g, Order No. 672-A, FERC
Stats. & Regs. ] 31,212 (2006).
    \11\ North American Electric Reliability Corp., 116 FERC ]
61,062, order on reh'g and compliance, 117 FERC ] 61,126 (2006)
(certifying NERC as the ERO responsible for the development and
enforcement of mandatory Reliability Standards), aff'd sub nom.
Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
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B. Reliability Standard FAC-003-2 and NERC Explanation of Provisions
\12\
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    \12\ Reliability Standard FAC-003-2 is not attached to the Final
Rule. The complete text of Reliability Standard FAC-003-2 is
available on the Commission's eLibrary document retrieval system in
Docket No. RM12-4-000 and is posted on the ERO's Web site, available
at: http://www.nerc.com.
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    8. Reliability Standard FAC-003-2 includes seven requirements.\13\
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    \13\ The NOPR also provided background on the requirements of
the Version 1 standard, FAC-003-1, and the Commission's directives
pertaining to the Version 1 standard set forth in Order No. 693. See
NOPR, 141 FERC ] 61,046 at PP 8-16.
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    9. Requirements R1 and R2: Pursuant to Requirements R1 and R2,
subsection 1, transmission owners must ``manage vegetation to prevent
encroachments into the MVCD of its applicable line(s),'' and any
encroachment is considered a violation of these requirements regardless
of whether it results in a sustained outage.\14\ In its petition, NERC
characterized this as a ``zero tolerance'' approach to vegetation
management.\15\ According to NERC, these requirements represent an
improvement over the Version 1 standard because FAC-003-2 makes the
requirement to prevent encroachments explicit, and because it
incorporates specific clearance distances into the standard itself
based on ``an established method for calculating the flashover distance
for various voltages, altitudes, and atmospheric conditions.'' \16\
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    \14\ See Reliability Standard FAC-003-2, Requirements R1 and R2,
subsection 1 (transmission owners must manage vegetation to prevent,
inter alia, ``an encroachment into the MVCD, as shown in FAC-003-
Table 2, observed in Real-Time, absent a Sustained Outage'').
    \15\ NERC Petition at 6.
    \16\ Id. at 22.
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    10. In addition, FAC-003-2 includes a footnote describing certain
conditions or scenarios, outside the transmission owner's control,
where an encroachment would be exempt from Requirements R1 and R2,
including natural disasters and certain human or animal activity.\17\
In its petition, NERC explained that the footnote ``does not exempt the
Transmission Owner from responsibility for encroachments caused by
activities performed by their own employees or contractors, but it does
exempt them from responsibility when other human activities, animal
activities, or other environmental conditions outside their control
lead to an encroachment that otherwise would not have occurred. '' \18\
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    \17\ See proposed Reliability Standard FAC-003-2, n.2.
    \18\ NERC Petition at 23.
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    11. Requirement R3: Requirement R3 requires a transmission owner to
have ``documented maintenance strategies or procedures or processes or
specifications it uses to prevent the encroachment of vegetation into
the MVCD of its applicable lines.'' Requirement R3 requires that these
strategies take into account movement of conductors (sag and sway), and
the inter-relationship between vegetation growth rates, vegetation
control methods, and inspection frequency. While NERC acknowledged that
this requirement does not include the Version 1 standard's requirement
to establish a Clearance 1, NERC noted that Clearance 1 levels are left
largely to the discretion of the transmission owner and that the only
numerical criterion for Clearance 1 is that it ``must be some undefined
amount larger than the minimum flashover distance [Clearance 2].'' \19\
According to NERC, the FAC-003-2 requirement to avoid encroachments
after taking into account conductor movement, vegetation growth rates,
etc., ``still retains the same obligations defined by `Clearance 1.' ''
\20\
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    \19\ Id. at 20. Requirement R1 of the Version 1 standard
requires a transmission owner to prepare a transmission vegetation
management program that includes, inter alia, a Clearance 1 distance
to be maintained at the time of vegetation management work, and a
Clearance 2 distance to be maintained at all times. See NOPR, 141
FERC ] 61,046 at P 9.
    \20\ NERC Petition at 20.
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    12. Requirement R4: Requirement R4 requires a transmission owner
that has observed a vegetation condition likely to produce a fault at
any moment to notify, ``without any intentional time delay,'' the
appropriate control center with switching authority for that
transmission line.
    13. Requirement R5: Requirement R5 requires a transmission owner
constrained from performing vegetation management work needed to
prevent a vegetation encroachment into the MVCD prior to implementation
of the next annual work plan to take corrective action to prevent such
encroachments. NERC stated in its petition that Requirement 5 improves
upon the Version 1 standard provision, Requirement R1.4, which merely
requires a transmission owner to develop mitigation measures to address
such circumstances, but does not affirmatively require the transmission
owner to take corrective action. The proposed measures for determining
compliance associated with proposed Requirement R5 provide examples of
the kinds of corrective actions expected, including increased
monitoring, line de-ratings, and revised work orders.\21\
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    \21\ See id. at 24-25.
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    14. Requirement R6: Pursuant to Requirement R6, each transmission
owner must inspect 100 percent of its applicable transmission lines at
least once per year and with no more than 18 months between inspections
on the same right-of-way. According to NERC, Requirement R6 is ``an
improvement to the standard that reduces risks.'' \22\ NERC noted that
the Version 1 standard allows a transmission owner to develop its own
schedule for inspections (with no standard minimum time) and contains
no explicit requirement that the transmission owner meet its
established schedule.
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    \22\ Id. at 17-18.
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    15. Requirement R7: Pursuant to Requirement R7, the transmission
owner must complete 100 percent of its annual vegetation work plan,
allowing for documented changes to the work plan as long as those
modifications do not allow encroachment into the MVCD. NERC explained
in its petition that Requirement R7 represents an improvement because
Requirement R2 of the Version 1 standard ``does not mandate that
entities plan to prevent encroachments into the MVCD, but simply that
they implement whatever is included in the plan.'' \23\
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    \23\ Id. at 28. For additional background pertaining to NERC's
petition, see NOPR, 141 FERC ] 61,046 at PP 32-36.
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C. Procedural Activities

1. Pacific Northwest National Laboratory Report
    16. NERC explained in its petition that the Standard Drafting Team
applied the ``Gallet equation'' to derive the MVCDs set forth in FAC-
003-2. NERC described the Gallet equation as a ``well-

known method of computing the required strike distance for proper
insulation coordination.'' \24\ The Commission's Office of Electric
Reliability retained the Pacific Northwest National Laboratory (PNNL)
to undertake an ``analysis of the mathematics and documentation of the
technical justification behind the application of the Gallet equation
and the assumptions used in the technical reference paper [Exh. A of
NERC's petition].'' \25\
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    \24\ NERC Petition, Ex. I (Technical Reference Document) at 39.
    \25\ See April 23, 2012 Notice Inviting Comments on Report.
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    17. PNNL's final Report on the Applicability of the ``Gallet
Equation'' to the Vegetation Clearances of NERC Reliability Standard
FAC-003-2 (PNNL Report) was posted as part of the record in this docket
on April 23, 2012, along with a notice inviting comment on the PNNL
Report within 30 days. Nine entities submitted comments in response to
the PNNL Report.\26\
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    \26\ For further description of the PNNL Report and comments
filed in response to the Report, see NOPR, 141 FERC ] 61,046 at PP
40-54.
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2. NERC Response to Data Request
    18. On May 4, 2012, Commission staff issued data requests to NERC.
NERC submitted a timely response to the data requests on May 25, 2012,
addressing matters such as the correct understanding and enforceability
of certain provisions of the proposed Reliability Standard. Relevant
elements of NERC's response to the data requests are discussed further
below.
3. Notice of Proposed Rulemaking
    19. On October 18, 2012, the Commission issued a NOPR proposing to
approve Reliability Standard FAC-003-2. In addition to seeking comment
on various aspects of NERC's petition, the Commission proposed to
direct that NERC: (1) Conduct or commission testing to obtain empirical
data that either confirms the MVCD values or gives reason to revisit
the Reliability Standard and submit a report to the Commission
providing the results of the testing; and (2) submit a modification
that assigns a ``high'' Violation Risk Factor for Requirement R2.
    20. Comments were due on December 24, 2012. Twenty sets of comments
were received. The Appendix to the Final Rule identifies the name of
commenters. The comments were informative and assisted the Commission
in developing this Final Rule. On February 5, 2013, NERC submitted
reply comments.

II. Discussion

    21. Pursuant to section 215(d) of the FPA, we approve Reliability
Standard FAC-003-2, including the associated definitions and
implementation plan, as just, reasonable, not unduly discriminatory or
preferential, and in the public interest. As discussed in Section A
below, we believe the proposed Reliability Standard will enhance
reliability and satisfies a number of the directives from Order No.
693. We also discuss the following matters below: (A) Approval of FAC-
003-2; (B) applicability of the standard to sub-200 kV transmission
lines; (C) clearance distances; (D) appropriate Violation Risk Factor
for Requirement R2; (E) enforcement issues; (F) inclusion of reporting
obligations as a compliance measure; and (G) proposed definitions.

A. The Commission Approves Reliability Standard FAC-003-2

NOPR Proposal
    22. In the NOPR, the Commission proposed to approve FAC-003-2,
explaining that it improves upon the Version 1 standard by supporting
vegetation management practices that can effectively protect against
vegetation-related transmission outages, and by satisfying a number of
the outstanding directives from Order No. 693.\27\ The Commission
highlighted several improvements, including the expanded applicability
of the Reliability Standard so that it now applies not only to all
transmission lines above 200 kV, but also to transmission lines
operated below 200 kV if they are an element of an IROL or an element
of a Major WECC Transfer Path. The Commission also highlighted that
FAC-003-2 incorporates (1) minimum clearance distances into the text of
the Reliability Standard and (2) a minimum inspection cycle
requirement.
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    \27\ NOPR, 141 FERC ] 61,046 at PP 57-61.
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Comments
    23. NERC supports the Commission's proposal to approve the proposed
Reliability Standard, stating that FAC-003-2 represents a significant
step in transmission vegetation management. According to NERC, FAC-003-
2 maintains reliability by using a defense-in-depth strategy to manage
vegetation located on transmission rights-of-way and by minimizing
vegetation encroachments within the transmission owner's control, thus
``preventing the risk of those vegetation-related outages that could
lead to a Sustained Outage.'' \28\ Further, NERC requests that the
Commission give ``due weight'' to NERC's technical expertise and
approve FAC-003-2 as filed.
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    \28\ NERC Comments at 3.
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    24. Trade Associations support approval of FAC-003-2, stating that
the revised Reliability Standard responds to the Commission directives
in Order No. 693 and provides a strong defense-in-depth approach to
vegetation management, including a requirement for at least annual
inspections.\29\ Trade Associations agree with the Commission's
statement in the NOPR that FAC-003-2 explicitly states minimum
clearance distances and that the modified ``applicability'' provision
includes additional facilities. Trade Associations state that FAC-003-2
strikes the appropriate balance between establishing minimum criteria
and permitting utility-specific variations that will enhance
reliability and prevent outages caused by vegetation intrusion.
Likewise, AEP, BPA, Idaho Power, ITC Companies, KCPL, Manitoba Hydro,
PacifiCorp, PA PUC, PG&E and Southern Companies support approval of
FAC-003-2 as an improvement over the currently-effective Reliability
Standard, and as addressing the Commission's directives in Order No.
693.
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    \29\ Duke, KCPL, PacifiCorp, PG&E and Southern Companies support
the comments submitted by Trade Associations.
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    25. NESCOE generally supports FAC-003-2 as representing appropriate
enhancements to the Version 1 standard in a number of critical areas.
While noting that the Reliability Standard is not designed to address
severe weather events and natural disasters such as the October 2011
Northeast snowstorm, NESCOE states that more clearly defined clearance
requirements and stricter vegetation management practices should have
the attendant benefit of reducing the risk to Bulk-Power System
reliability during such events. However, NESCOE believes that NERC
should be required to demonstrate that the proposal is supported by a
cost analysis, i.e., that the incremental reliability gains outweigh
the added costs. Therefore, NESCOE recommends that the Commission grant
``interim approval'' to FAC-003-2, with final approval conditioned on
NERC supporting the proposal with a cost-benefit analysis.
    26. APS comments that the Version 1 standard, FAC-003-1, has proven
effective and the Commission should consider ``maintaining'' that
standard. APS notes that the number of outages caused by vegetation
grow-in has steadily declined since implementation of the Version 1
standard, and APS

attributes this decline largely to the ``Clearance 1'' requirement that
transmission owners develop and document their plan to manage the
vegetation on rights-of-way at the time of work. APS expresses concern
that a different approach may be less effective. Alternatively, if FAC-
003-2 is approved, APS suggests integrating a Clearance 1 requirement
in that standard.
Commission Determination
    27. We adopt our NOPR proposal and approve Reliability Standard
FAC-003-2, including the associated definitions and implementation
plan, as just, reasonable, not unduly discriminatory or preferential,
and in the public interest.\30\ We find that FAC-003-2 is an
improvement over the currently-effective Version 1 standard, will
support vegetation management practices that can effectively protect
against vegetation-related transmission outages, and satisfies a number
of the outstanding directives from Order No. 693. As discussed earlier,
NERC has explained how many of the Requirements improve upon the
currently-effective Version 1 standard. In accordance with our
directives in Order No. 693, and as discussed further in Section II.B
below, NERC has expanded the applicability of the Reliability Standard
so that it now applies not only to all transmission lines operated
above 200 kV, but also to transmission lines operated below 200 kV if
they are an element of an IROL or an element of a Major WECC Transfer
Path.
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    \30\ Likewise, we approve as requested by NERC, the retirement
of FAC-003-1 and the current definitions of ``right-of-way'' and
``vegetation inspection'' effective ``midnight immediately prior to
the first day of the first calendar quarter that is a year following
the effective date'' of the final rule. NERC Petition at 2.
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    28. In addition, NERC has incorporated minimum clearance distances
into the text of the Reliability Standard, and no longer includes a
required clearance distance based on a reference to distances set by
Institute of Electric and Electronics Engineers (IEEE) Standard 516
that, as indicated in Order No. 693, served a different purpose than
vegetation management. Proposed FAC-003-2 requires a transmission owner
to prevent an encroachment into the MVCD, even if the encroachment does
not result in a flashover or fault. As NERC explains, ``FAC-003-2
presents a `zero-tolerance' approach to vegetation management,
explicitly treating any encroachment into the MVCD* * * as a violation*
* *.'' \31\ Encroachments must be prevented under all rated operating
conditions, and strategies to prevent encroachments must take into
account sag and sway of the line, as well as vegetative growth rates
and frequency of inspection and maintenance.\32\
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    \31\ NERC Petition at 6.
    \32\ See Reliability Standard FAC-003-2 at p 20-22.
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    29. Further, in Order No. 693 the Commission expressed concern that
the Version 1 standard leaves to the discretion of each transmission
owner to determine inspection cycles.\33\ In response, NERC has
addressed this concern by incorporating a minimum inspection cycle
requirement in the proposed Reliability Standard (at least once per
calendar year and no more than 18 months between inspections).\34\
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    \33\ See NOPR, 141 FERC ] 61,046 at P 59 (citing Order No. 693,
FERC Stats. & Regs. ] 31,242 at P 721).
    \34\ See NERC Petition at 43.
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    30. The Commission disagrees with APS and will not maintain the
Version 1 standard. While we agree with APS that the Version 1 standard
has proven effective in minimizing the number of outages caused by
vegetation grow-in, as described above, we conclude that FAC-003-2
includes improvements upon the Version 1 standard. We expect these new
features to enhance vegetation management practices and continue the
decline in reported vegetation-related outages. Moreover, with regard
to APS's concerns on the elimination of the ``Clearance 1''
requirement, we do not believe that this concern supports maintaining
the Version 1 standard. As we discuss in more detail later on, under
FAC-003-2, transmission owners will manage vegetation to distances
beyond the MVCD to ensure no encroachment into the MVCD.\35\ Therefore,
we are not persuaded that APS's concerns warrant a remand of FAC-003-2.
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    \35\ See discussion infra section II.C.1 (Minimum Clearance
Values); see also NOPR, 141 FERC ] 61,046 at PP 67-70 (discussing
NERC Petition and maintenance of vegetation beyond MVCD values).
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    31. We also disagree with NESCOE that the Commission should grant
``interim approval'' to FAC-003-2, with final approval conditioned on
NERC supporting the proposal with a cost-benefit analysis. As NESCOE
acknowledges, the Reliability Standard includes enhancements to the
Version 1 standard in a number of critical areas. Section 215(d) of the
FPA authorizes the Commission to approve or remand a Reliability
Standard proposed by the ERO. There is no mention of authority to
approve a standard on an ``interim'' basis, or what that approval would
entail. In addition, as the Commission has stated, while the cost of
implementation is appropriate for consideration among other factors in
the development of a Reliability Standard, the Commission has not
required the preparation of a cost-benefit analysis for approval of a
standard.\36\
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    \36\ See North American Electric Reliability Corp., 117 FERC ]
61,126 at P 97 (2006); see also Order No. 672, FERC Stats. & Regs. ]
31,204 at P 330. To the extent estimated costs are considered,
estimated benefits (e.g., in terms of a level of reliability or the
risk, duration, scope or economic savings of avoided blackouts) must
be considered, either quantitatively or (if quantification is
impractical) qualitatively.
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    32. Accordingly, we approve FAC-003-2 on a final basis, and
transmission owners must comply with the Reliability Standard as set
forth in NERC's implementation plan.

B. Applicability--Facilities Operated Below 200 kV

NOPR Proposal
    33. The Reliability Standard applies to transmission owners.
Further, FAC-003-2 applies to (1) overhead transmission lines operated
at 200 kV or higher and (2) overhead lines operated below 200 kV if (a)
``identified as an element of an IROL under NERC Standard FAC-014 by
the Planning Coordinator'' or (b) ``identified as an element of a Major
WECC Transfer Path* * *'' In the NOPR, the Commission asked how IROL
status of a facility will be communicated to transmission owners, and
how transmission owners can effectively implement this provision since
IROL status can change with system conditions.\37\ Further, the
Commission asked for comment on how FAC-003-2 complies with the Order
No. 693 directive that the standard cover ``lines that have an impact
on reliability.'' \38\
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    \37\ NOPR, 141 FERC ] 61,046 at P 64.
    \38\ NOPR, 141 FERC ] 61,046 at P 65, quoting Order No. 693,
FERC Stats. & Regs. ] 31,242 at P 708.
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1. Identification and Communication of IROL Status
Comments
    34. NERC comments that FAC-003-2 relies on the identification of
IROLs by the planning coordinator, which ``would include identifying
any changes in the status of a line if a line's IROL status changes
given changing system conditions.'' \39\ NERC further states that
Requirement R5 of FAC-014 provides the means for a transmission owner
to obtain IROL information. According to NERC, this provision requires
the planning authority (a term synonymous

with planning coordinator) to ``provide its SOLs and IROLs to entities
with a reliability-related need, such as a Transmission Owner, who
request such information.'' \40\ NERC further offers that ``[i]f the
Commission does not agree that Transmission Owners can obtain
information directly from Planning Coordinators under Requirement R5 of
FAC-014,'' transmission owners have other means such as Requirement R8
of Reliability Standard TPL-001-2 as well as existing agreements
between transmission owners and transmission operators.\41\ Regarding
changes in IROL status, NERC comments that the burden is on the
transmission owner to procure this information as part of its
responsibility to manage vegetation to prevent encroachment and as the
entity responsible for implementing FAC-003-2.
---------------------------------------------------------------------------

    \39\ NERC Comments at 5.
    \40\ Id. See also Technical Reference Document at p. 12.
    \41\ NERC Comments at 5-6.
---------------------------------------------------------------------------

    35. Likewise, Duke states that, pursuant to FAC-014, a transmission
owner can request IROL designations from the planning coordinator,
including future changes to IROL status. Duke and AEP comment that FAC-
003-2 includes an effective date twelve months after the date a
transmission line operated below 200 kV is newly designated as an
element of an IROL. They state that this twelve-month period allows
time for the transmission owner to modify its vegetation management
work plan to include new IROL elements.
    36. According to Trade Associations, AEP and FirstEnergy, FAC-014
does not require planning coordinators to notify transmission owners of
the designation of IROL facilities. Further, Trade Associations
maintain that a vegetation management program is based on the near term
planning horizon of one to five years and, thus, applicable entities
cannot document compliance with day-to-day operating changes to IROLs.
Trade Associations comment that, while this issue should not delay
approval of FAC-003-2, it is important to establish a clearly defined
communication structure and agreed upon start date for compliance
documentation prior to transmission owners' inclusion of IROL elements
in their vegetation management programs.
    37. FirstEnergy and AEP advocate that the Commission direct NERC to
modify FAC-014 to include a requirement that planning coordinators
promptly communicate IROL status updates to transmission owners.
According to Idaho Power, FAC-003-2 should require that the planning
coordinator communicate IROL status to transmission owners. Moreover,
Idaho Power suggests that it is reasonable to hold a transmission owner
responsible for vegetation management on lines that can become IROLs
during ``studied credible contingencies'' but not for unstudied or
unanticipated system conditions.
    38. BPA suggests that NERC develop an automated electronic
notification system to inform affected transmission owners regarding
changes in IROL status.
Commission Determination
    39. Consistent with the NOPR, we remain concerned regarding how
IROL status of a facility will be communicated to transmission owners.
We are not persuaded that Reliability Standard FAC-014 requires the
communication of IROL status information to transmission owners.
Requirement R5 of FAC-014-2 provides:

    R5. The Reliability Coordinator, Planning Authority and
Transmission Planner shall each provide its SOLs and IROLs to those
entities that have a reliability-related need for those limits and
provide a written request that includes a schedule for delivery of
those limits as follows:
    R5.1. The Reliability Coordinator shall provide its SOLs
(including the subset of SOLs that are IROLs) to adjacent
Reliability Coordinators and Reliability Coordinators who indicate a
reliability-related need for those limits, and to the Transmission
Operators, Transmission Planners, Transmission Service Providers and
Planning Authorities within its Reliability Coordinator Area. * * *

    40. While Requirement R5 indicates that SOLs and IROLs should be
provided to entities that have a ``reliability-related need'' for that
information, this broad language is limited ``as follows'' to the
entities specified in sub-Requirement R5.1. Transmission owners are not
specified. Further, Requirement R5 of FAC-003 does not include ``for
example'' or ``including but not limited to'' language that would
suggest the entities specified in sub-Requirement R5.1 are not
exclusive. Thus, we conclude that FAC-014-2 does not obligate
reliability coordinators, planning authorities and transmission
planners to provide IROL information to transmission owners.\42\
---------------------------------------------------------------------------

    \42\ NERC also suggests that Requirement R8 of TPL-001-2
supports the communication of IROLs by transmission operators to
transmission owners. Proposed Reliability Standard TPL-001-2 has not
been approved as a mandatory Reliability Standard.
---------------------------------------------------------------------------

    41. Rather, we agree with Trade Associations and other commenters
that NERC should establish a clearly defined communication structure to
assure that IROLs and changes to IROL status are timely communicated to
transmission owners. This structure will better support compliance with
the extended applicability of FAC-003-2 to sub-200 kV transmission
lines that are an element of an IROL. One way to achieve this
objective, as advocated by AEP and others, is to modify FAC-014 to
require the provision of IROLs to transmission owners. However, we
leave it to NERC to determine the most appropriate means for
communicating IROL status to transmission owners.
    42. We do not believe, however, that establishing a communication
structure should delay the implementation of FAC-003-2. As NERC
indicates, the ultimate responsibility for compliance with FAC-003-2 is
upon transmission owners. Moreover, it appears that there are multiple
avenues for transmission owners to obtain information about IROL
elements on their facilities. For example, NERC represents that, in
many instances, the entity responsible for identifying IROL elements on
a system is also registered as a transmission owner.\43\ Likewise,
transmission owners may obtain the necessary information through
voluntary communications or pursuant to coordination required in
bilateral agreements. As Duke and AEP note, FAC-003-2 includes an
effective date that is twelve months after the date a line operated
below 200 kV is initially designated as an element of an IROL, which
allows time for the transmission owner to modify its vegetation
management work plan to include new IROL elements. We encourage NERC to
inform us when it has developed means for communication of IROLs to
transmission owners to help ensure they receive notice of each of their
applicable lines before the standard becomes effective as to those
lines.
---------------------------------------------------------------------------

    \43\ See NERC Comments at 5-6.
---------------------------------------------------------------------------

    43. With regard to the concern in the NOPR on the changing status
of IROLs, we accept the explanation of Trade Associations that a
vegetation management program should be based on the near term planning
horizon of one to five years, in which case applicable transmission
owners will not be responsible to document compliance with day-to-day
operating changes to IROLs. Likewise, we agree with Idaho Power that
transmission owners should be responsible for vegetation management on
lines that can become IROLs during ``studied credible contingencies.''
Based on the methodology set forth in FAC-014, sub-200 kV transmission
lines that are identified as elements of an IROL or Major WECC Transfer
Path are subject to FAC-003-2. For example, some entities

identify seasonal IROLs and we expect sub-200 kV elements of seasonal
IROLs to be subject to FAC-003-2.\44\ In contrast, as suggested by
Idaho Power, if, for example, a multiple contingency results in the
operation of the system in an unknown state for a limited period of
time, a transmission owner is not responsible for compliance with FAC-
003-2 with respect to IROLs that may result from temporary operation in
that unknown state. We believe that this approach provides consistency
and predictability in identifying the sub-200 kV transmission lines
that are subject to compliance with FAC-003-2.
---------------------------------------------------------------------------

    \44\ Most likely, transmission owners do not manage vegetation
under or near a line seasonally as it moves in/out of IROL status,
and instead do so on a year-round basis. In other words, as a
practical matter, a seasonal IROL is maintained throughout the year.
---------------------------------------------------------------------------

    44. Finally, with regard to BPA's suggestion, we will not direct
that NERC develop an automated electronic notification system to inform
affected transmission owners of changes in IROL status. BPA may propose
this directly to NERC, and NERC can determine whether this is an
appropriate activity.
2. Coverage of Lines That Have an Impact on Reliability
Comments
    45. NERC maintains that, consistent with Order No. 693, it has
properly modified the applicability of FAC-003-2 to include
transmission lines that have an impact on reliability while balancing
the extension of the applicability of the standard against unreasonably
increasing the burden on transmission owners.\45\ According to NERC,
rather than employing a bright-line threshold of 100 kV, the standard
drafting team chose to limit sub-200 kV applicability to ``specific
cases where lines are critical to reliability by virtue of their
inclusion as elements in the determination of an IROL or a part of a
Major WECC Transfer Path.'' \46\ NERC states that, by relying on IROL
and Major WECC Transfer Path identification as a ``proxy'' for
reliability importance, FAC-003-2 uses an ``impact-based approach'' for
determining applicability. Similarly, Duke asserts that FAC-003-2
appropriately covers lines that have an impact on reliability by
including sub-200 kV lines that are either an element of an IROL or a
major WECC Transfer Path.
---------------------------------------------------------------------------

    \45\ NERC Comments at 8. NERC notes that the Commission in Order
No. 693 directed NERC to ``modify the Reliability Standard to apply
to Bulk-Power System transmission lines that have an impact on
reliability as determined by the ERO.'' Id.
    \46\ Id. at 8-9.
---------------------------------------------------------------------------

    46. PacifiCorp and NESCOE comment that FAC-003-2 appropriately
balances the inclusion of certain sub 200-kV lines based on IROLs with
the risk of over-capturing elements that do not present a risk of
cascading outages. NESCOE states that this balance ``takes into account
the burden placed on transmission owners and, implicitly costs
ultimately borne by consumers.'' \47\
---------------------------------------------------------------------------

    \47\ NESCOE Comments at 6.
---------------------------------------------------------------------------

    47. In response to the NOPR question regarding how NERC will assure
that IROLs are properly designated in light of the 2011 Southwest
Outage, NERC states that it will continue to enforce FAC-014 and FAC-
010 to ensure that planning coordinators identify IROLs using their
developed methodology. NERC also states that efforts are underway to
implement recommendations of the Outage Report addressing the failure
to properly designate IROLs.
Commission Determination
    48. The Commission accepts NERC's explanation that it has properly
modified the applicability of FAC-003-2 to include transmission lines
that have an impact on reliability. We agree with NERC that, by making
the applicability of sub-200 kV transmission lines dependent on
operating impacts, i.e., elements of IROLs and Major WECC Transfer
Paths, the Reliability Standard reasonably balances enhanced
applicability of the standard with unreasonably increasing the burden
on transmission owners without commensurate reliability gains.
    49. With regard to the Commission's question in the NOPR regarding
how NERC will assure that IROLs are properly designated in light of the
2011 Southwest Outage,\48\ we are satisfied with NERC's explanation
that (a) NERC will continue to enforce FAC-014 and FAC-010 to ensure
that planning coordinators identify IROLs using their developed
methodology and (b) efforts are underway to implement recommendations
of the Outage Report addressing the failure to properly designate
IROLs.
---------------------------------------------------------------------------

    \48\ NOPR, 141 FERC ] 61,046 at P 65.
---------------------------------------------------------------------------

C. Requirements R1 and R2

1. Minimum Clearance Values
NOPR Proposal
    50. In the NOPR, the Commission stated that ``[b]ased on the record
in this proceeding, the application of the Gallet equation appears to
be one reasonable method to calculate MVCD values.'' \49\ The
Commission further stated that NERC ``has supported the inputs and
assumptions it used to develop those minimum clearance distances, at
least until such time that empirical data is developed and is available
for use in setting MVCDs.'' \50\ The Commission, however, explained
that it remained concerned over the lack of empirical data with regard
to actual flashover distances observed through testing or analysis of
flashover events.\51\
---------------------------------------------------------------------------

    \49\ NOPR, 141 FERC ] 61,046 at P 71.
    \50\ NOPR, 141 FERC ] 61,046 at P 66.
    \51\ NOPR, 141 FERC ] 61,046 at P 72 (citing Order No. 693, FERC
Stats. & Regs. ] 31,242 at P 735).
---------------------------------------------------------------------------

    51. NERC, in its petition, indicated that Electric Power Research
Institute (EPRI) is planning to undertake field tests of energized high
voltage conductor flash-over to vegetation, and the NOPR asked for
information on the status of the testing. In the NOPR, the Commission
proposed to direct that NERC conduct or commission testing to obtain
empirical data and submit a report to the Commission providing the
results of the testing.
Comments
    52. EPRI, in its comments, provides an update on the status of its
testing. EPRI states that, beginning in June 2009, it planted
vegetation on a test right-of-way at EPRI's facilities, intended for
high voltage air gap spark-over research. EPRI explains that it can
raise and lower the test line, and adjust the test line voltage, to
create the desired spark-over scenario. According to EPRI, with
appropriate funding and designation of scope, testing can begin in the
summer of 2013. EPRI recommends that a study designed to improve
understanding of gap flash over to trees should focus primarily on
validation of the Gallet equation, and specifically the flashover
characteristics of a conductor to a grounded rod. EPRI states that it
is committed to working with the Commission and other entities to
develop an appropriate project scope, to estimate the required funding
and solicit that funding.
    53. NERC asks that, due to uncertainty in timing, funding, design,
scope and execution of a study to develop empirical data, the
Commission refrain from issuing a directive that NERC conduct or
commission testing. NERC suggests that, as an alternative, the
Commission ``accept NERC's commitment'' to work with the Commission and
other entities to determine ``whether and how a study could be
conducted to obtain the empirical data the Commission seeks * * *''
\52\ According to NERC, this alternative approach would allow NERC

flexibility to discuss study scope and funding with the Commission,
allow for the development of partnerships in conducting the study, and
allow collaboration on the study and any necessary changes to the
Reliability Standard. NERC asks that, if directed to conduct empirical
research, the Final Rule address (1) the need for the empirical data
and scope of the study, (2) time frame for the study--and allow NERC to
submit a proposed schedule for completion, and (3) funding of the
study.
---------------------------------------------------------------------------

    \52\ NERC Comments at 10.
---------------------------------------------------------------------------

    54. Trade Associations support EPRI conducting research ``to the
extent needed,'' and submitting a preliminary report with initial
observations by first quarter 2014. Trade Associations state that EPRI
has the skills and equipment necessary to conduct testing, but add that
funding ``may be a challenge'' since EPRI does not have a dedicated
funding source. Trade Associations comment that there needs to be a
clearer understanding of the scope and timeline for the research, and
urge limiting the scope and subsequent report to validating the ``gap
factors'' used to represent the ``air gap'' between a conductor and
vegetation. Trade Associations, as well as Duke, advocate that the
study not focus on validating the appropriateness of the Gallet
equation for use in determining MVCDs, as that testing and validation
has already taken place. Trade Associations add that, as an alternative
to a Commission directive, the Commission could consider informal
discussions with NERC and stakeholders to inform decisions on the scope
and timing of the research, and how to most effectively ensure strong
project management and funding.
    55. AEP, BPA, Duke, Idaho Power and PacifiCorp also support the
proposal to direct testing of the MVCDs calculated by the Gallet
equations, and support EPRI conducting such field testing or research.
Idaho Power recommends directing that NERC submit a report within one
year of a final rule approving FAC-003-2. AEP, however, believes that
it would be premature to impose a schedule for the testing until
funding is procured.
    56. On a related matter, regarding compliance with MVCD values in
Requirements R1 and R2, PacifiCorp and APS comment that the only way to
prove that the MVCD has not been violated under all rated conditions
and all sag/sway scenarios is to employ Light Detection and Ranging
(LiDAR) on a continuous basis. PacifiCorp recommends that, because this
approach is cost prohibitive, FAC-003-2 should be revised in a
subsequent version to return to the language of the Version 1 standard
that allows transmission owners to remedy Clearance 2 encroachments
prior to an outage without a violation. APS requests clarification
regarding the need to demonstrate compliance at all rated conditions so
that transmission owners can design their vegetation management plans
appropriately and reduce the risk of violation.
    57. APS comments that, while the Gallet equation appears to be a
reasonable method to calculate MVCD values, it shares the Commission's
concern regarding the lack of empirical data on actual flashover
distances and supports the proposed directive for field tests of
energized high voltage conductor flashover to vegetation. APS suggests
that the United States Department of Energy (DOE) conduct the study,
with a completion date of first quarter 2014.
    58. Moreover, APS expresses concern that FAC-003-2 does not carry
over the Clearance 1 requirement set forth in the current Version 1
standard. According to APS, the requirement to maintain Clearance 1 is
a primary cause of the success of the Version 1 standard in reducing
vegetation-related outages. APS also states that Clearance 1 clarifies
that federal, state, and other agencies do not have the authority or
responsibility to determine clearances on rights-of-way. According to
APS, Clearance 1 ``gives legitimacy'' to transmission owners in
discussions with federal agencies for clearance distances that are
greater than the minimum required, i.e., Clearance 2 distances. APS,
therefore, advocates that the Commission either maintain the Version 1
standard or ``integrate'' a Clearance 1 requirement into FAC-003-2.
Commission Determination
    59. We adopt the NOPR proposal and direct NERC to conduct or
contract testing to develop empirical data regarding the flashover
distances between conductors and vegetation. The data obtained from
such studies should be informative of the appropriateness and accuracy
of the MVCD values for various voltage ratings as set forth in FAC-003-
2. While NERC can develop the specific parameters for such testing,
generally, repeated application of high voltage injections into a test
line under set conditions would provide evidence of sparkover events. A
statistical analysis would then evaluate the test results and provide
empirical evidence to support an appropriate gap factor to be applied
in calculating minimum clearance distances using the Gallet
equation.\53\
---------------------------------------------------------------------------

    \53\ We will not specify that NERC retain EPRI or any other
particular entity to conduct the required testing.
---------------------------------------------------------------------------

    60. In response to Trade Associations, we are not directing NERC to
reconsider use of the Gallet equation in determining MVCD values as set
forth in the Reliability Standard. As we stated in the NOPR, and adopt
in the Final Rule, the application of the Gallet equation appears to be
one reasonable method to calculate MVCD values.\54\ However, MVCD
calculations based on the Gallet equation depend on certain
assumptions, such as the appropriate ``gap factor.'' NERC previously
indicated that it relied on a ``widely known and regarded source for
determining the appropriate gap factor.'' \55\ It nonetheless is clear
that the gap factor NERC applied in the Gallet equation to calculate
MVCD values was not based on empirical data. If such inputs into the
calculation prove to be inaccurate, in a worst case scenario,
flashovers from vegetation to a conductor could occur at the MVCD
values identified in the Reliability Standard. While NERC's use of the
Gallet equation and the resulting MVCD values are reasonable based on
the information available in this docket, minimum clearance values are
too important to reliability to ultimately rely on assumed inputs, and
empirical testing is appropriate to confirm the values used in the
equation.
---------------------------------------------------------------------------

    \54\ NOPR, 141 FERC ] 61,046 at P 71.
    \55\ See NOPR, 141 FERC ] 61,046 at P 47.
---------------------------------------------------------------------------

    61. NERC asks that we accept its commitment to move forward with
the study. However, our determination that such a study is needed
warrants imposing a directive for its completion. Thus, we direct NERC,
within 45 days of the effective date of this Final Rule, to submit an
informational filing that includes, inter alia: (1) A schedule for
testing, (2) scope of work, (3) funding solutions, and (4) deadline for
submitting a final report to the Commission on the test results (and
interim reports if a multi-year study is conducted). This approach
should give NERC the flexibility to consult with the Commission or its
staff as well as industry members to determine the technical
specifications for the required study, funding sources and timing.
However, given the importance of the testing set forth in our
determination, the filing and schedule must include a reasonable date
for the submission of a final report on the results of the empirical
study.
    62. With regard to the comments of PacifiCorp and APS on compliance
with

the MVCD values under all rated conditions, we disagree that FAC-003-2
should be revised to allow transmission owners to remedy MVCD
encroachments prior to an outage without a violation. NERC indicates
that, under FAC-003-2, transmission operators will manage vegetation to
distances beyond the MVCD to ensure no encroachment into the MVCD.\56\
Thus, in response to PacifiCorp and APS, a vegetation management
strategy required by Requirement R3 of FAC-003-2 must provide enough
clearance to ensure that the MVCD will not be encroached under any
conditions.
---------------------------------------------------------------------------

    \56\ See NOPR, 141 FERC ] 61,046 at PP 67-70 (discussing NERC
Petition and maintenance of vegetation beyond MVCD values).
---------------------------------------------------------------------------

    63. We are not persuaded by APS's concern that the Commission
should carry over the Clearance 1 requirement to FAC-003-2. In the
NOPR, the Commission provided a detailed explanation, based on the NERC
petition, regarding how transmission owners are expected to comply with
the clearance requirements set forth in Requirements R1 and R2 of FAC-
03-2. The MVCD clearances represent only one aspect of FAC-003-2. The
MVCD establishes a ``minimum[] required to prevent Flash-over.'' \57\
Reliability Standard FAC-003-2 requires transmission owners to manage
vegetation to ensure that vegetation does not encroach into the MVCD,
which in turn requires transmission owners to manage vegetation to a
distance further than the MVCD. For example, transmission owners are
required to have documented compliance strategies, procedures,
processes, or specifications under Requirement R3 to prevent
encroachments into the MVCDs after taking into account sag and sway of
the lines, as well as vegetative growth rates, planned control methods
and frequency of inspections.\58\ Similarly, under Requirement R7, a
transmission owner is required to ``complete 100% of its annual
vegetation work plan of applicable lines to ensure no vegetation
encroachments occur within the MVCD.'' \59\ As NERC has explained, the
``Transmission Owner is obligated to show detailed documentation that
clearly explains their system with regard to the geography and how the
Transmission Owner will execute the plan to prevent encroachment.''
\60\ Further, according to the NERC petition, a transmission owner's
documentation approach will generally contain certain specific elements
including ``the maintenance strategy used (such as minimum vegetation-
to-conductor distance or maximum vegetation height) to ensure that MVCD
clearances are never violated.'' \61\ Likewise, NERC indicated that
``prudent vegetation maintenance practices dictate that substantially
greater distances [than the applicable MVCD] will be achieved at time
of vegetation maintenance.'' \62\
---------------------------------------------------------------------------

    \57\ NERC Petition, Ex. A (Proposed Reliability Standard FAC-
003-2) at 26 (Table 2--Minimum Vegetation Clearance Distances (MVCD)
for Alternating Current Voltages), n. 7 (emphasis added).
    \58\ NOPR, 141 FERC ] 61,046 at P 67.
    \59\ Reliability Standard FAC-003-2, Requirement R7.
    \60\ See NERC Response to Data Request Q2.
    \61\ NOPR, 141 FERC ] 61,046 at P 67.
    \62\ Id. (citing NERC Petition, Ex. A (Proposed Reliability
Standard FAC-003-2) at 26 (Table 2--Minimum Vegetation Clearance
Distances (MVCD) for Alternating Current Voltages), n. 7).
---------------------------------------------------------------------------

    64. NERC also explained that a conductor's position in space at any
point in time continuously changes in reaction to a variety of factors,
such as the amount of thermal and physical loading, air temperature,
wind velocity and direction, and precipitation. The following diagram
is a cross-section view of a single conductor at a given point along
the span that illustrates six possible conductor positions due to
movement resulting from thermal and mechanical loading: \63\
---------------------------------------------------------------------------

    \63\ NERC Petition, Ex. A at 20-21.
    [GRAPHIC] [TIFF OMITTED] TR28MR13.001

    NERC indicated that conductor movements must be taken into account
under FAC-003-2, and that the transmission owner is required to show
that its approach to vegetation management under Requirement R3 will
prevent encroachments under all expected line positions.\64\ Thus, a
transmission owner must manage vegetation to ensure it does not
encroach into the MVCD under multiple conditions.
---------------------------------------------------------------------------

    \64\ See id. and Requirement R3 of FAC-003-2; see also NERC
Petition, Ex. I (Technical Reference Document) at 20-29.
---------------------------------------------------------------------------

    65. Finally, as NERC explained in its Technical Reference Document,
transmission owners will have to clear vegetation to levels ``well away
from'' the minimum spark-over zone:

    As the conductor moves through various positions [due to thermal
loading and physical loading], a spark-over zone surrounding the
conductor moves with it.

* * * At the time of making a field observation, however, it is very
difficult to precisely know where the conductor is in relation to
its wide range of all possible positions. Therefore, Transmission
Owners must adopt maintenance approaches that account for this
dynamic situation.
* * * * *
    In order to maintain adequate separation between vegetation and
transmission line conductors, the Transmission Owner must craft a
maintenance strategy that keeps vegetation well away from the spark-
over zone mentioned above.\65\

    \65\ NERC Petition, Ex. I (Technical Reference Document) at 21-
24.

    66. Thus, while clearances required at the time of maintenance may
vary from one region or area to another, our proposed approval of FAC-
003-2 is based on our understanding, which is drawn directly from
NERC's statements in its petition, that transmission operators will
manage vegetation to distances beyond the MVCD to ensure no
encroachment into the MVCD.
    67. NERC's approach to setting MVCDs and maintaining vegetation is
reasonable and designed to provide flexibility while assuring that
transmission owners will proactively avoid encroachments into the MVCD.
Accordingly, we will not require the reinstatement of a Clearance 1
requirement in FAC-003-2 as requested by APS.
2. Violation Risk Factor for Requirement R2
NOPR Proposal
    68. The NOPR explained that NERC proposes to assign a ``high''
Violation Risk Factor to Requirement R1, which requires transmission
owners to ``manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) which are either an element of an IROL, or an
element of a Major WECC Transfer Path.'' Requirement R2, which is
assigned a ``medium'' Violation Risk Factor, provides that ``[e]ach
Transmission Owner shall manage vegetation to prevent encroachments
into the MVCD of its applicable line(s) which are not either an element
of an IROL, or an element of a Major WECC Transfer Path.'' \66\ The
Commission observed that the substantive obligations set forth in
Requirements R1 and R2 are identical, but the Violation Risk Factors
differ based on whether a transmission line is an element of an IROL or
Major WECC Transfer Path.
---------------------------------------------------------------------------

    \66\ Reliability Standard FAC-003-2, Requirement R2 (emphasis in
original).
---------------------------------------------------------------------------

    69. The Commission, in the NOPR, questioned whether this proposed
``bifurcation'' comported with the definition of ``medium'' Violation
Risk Factor and the Commission's guidelines for reviewing Violation
Risk Factor designations. The Commission also noted that transmission
lines not designated as elements of IROLs played a role in past
cascading outages. For these reasons, the Commission proposed to modify
the Violation Risk Factor for Requirement R2 from ``medium'' to
``high,'' and invited NERC to ``provide additional explanation * * * to
demonstrate the lines identified in Requirement R2 are properly
assigned a medium Violation Risk Factor.'' \67\
---------------------------------------------------------------------------

    \67\ NOPR, 141 FERC ] 61,046 at P 81.
---------------------------------------------------------------------------

Comments
    70. NERC comments that it ``does not have additional information
beyond the information supplied in its petition'' on this issue.\68\
NERC maintains that the ``medium'' designation is appropriate, aligns
with the definitions for Violation Risk Factors and complies with the
Commission's guidelines for such designations. According to NERC, the
separate designations for Requirements R1 and R2 recognize that an
element of an IROL or WECC Major Transfer Path is a ``greater risk'' to
the transmission system, while applicable lines that are not an element
of an IROL or Major WECC Transfer Path ``do require effective
vegetation management, but these lines are comparatively less
operationally significant.'' \69\
---------------------------------------------------------------------------

    \68\ NERC Comments at 13.
    \69\ NERC Comments at 13.
---------------------------------------------------------------------------

    71. Trade Associations ``do not disagree'' with the NOPR statement
that lines not designated as IROL or Major WECC Transfer Path may be
associated with higher-risk consequences including cascading outages.
Trade Associations, however, maintain that the test for a medium
Violation Risk Factor ``is not whether a violation could lead to system
instability, but whether it is likely (or unlikely) to occur.'' \70\
Thus, Trade Associations argue that the ``medium'' designation for
Requirement R2 is appropriate because lines that are not an element of
an IROL or Major WECC Transfer Path present a ``comparatively reduced
risk'' for cascading outages or system instability. Trade Associations
note that the Violation Risk Factor distinction between Requirements R1
and R2 received broad industry support and that the Commission's
proposal would reverse NERC and industry's consensus approach to the
development of FAC-003-2.
---------------------------------------------------------------------------

    \70\ Trade Association Comments at 5.
---------------------------------------------------------------------------

    72. Duke and Manitoba Hydro also oppose the designation of a
``high'' Violation Risk Factor for Requirement R2. Duke notes that the
definition of IROL is ``a System Operating Limit that, if violated,
could lead to instability, uncontrolled separation, or Cascading
Outages * * *'' and, thus, argues that a non-IROL line does not present
as great a risk for cascading outages or instability and should have a
lesser Violation Risk Factor.
Commission Determination
    73. We adopt our NOPR proposal and direct NERC to modify the
Violation Risk Factor for Requirement R2 from ``medium'' to ``high,''
within 45 days of the effective date of the Final Rule.
    74. The Commission-approved definition of a ``medium'' risk
requirement is:

    A requirement that, if violated, could directly affect the
electrical state or the capability of the bulk electric system, or
the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely
to lead to bulk electric system instability, separation, or
cascading failures * * *. \71\
---------------------------------------------------------------------------

    \71\ See North American Electric Reliability Corp., 119 FERC ]
61,145 at P 9, order on compliance, 121 FERC ] 61,179, at n.2, App.
A (2007) (emphasis added).

---------------------------------------------------------------------------
    The definition of a high Violation Risk Factor is:

    A requirement that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a
cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or
cascading failures * * *.\72\
---------------------------------------------------------------------------

    \72\ Id. (emphasis added).

    75. We are not persuaded by the response of NERC and others that a
medium Violation Risk Factor designation for Requirement R2 is
supported because there is a relatively greater risk of cascading
outages associated with a transmission line that is an element of an
IROL or Major WECC Transfer Path than with a line that is not. The
definition of ``medium'' Violation Risk Factor provides in part that
``violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures.'' In
the NOPR, the Commission questioned NERC's rationale, stating that
``NERC does not explain why outages on these relatively high voltage
lines (200 kV or higher) would not likely lead to cascading,
separation, or instability * * *'' \73\ Further, the Commission pointed
out that transmission lines not designated as an IROL element (or the
equivalent) have been instrumental in causing major blackouts,
including the August 2003

Northeast blackout and an August 10, 1996 blackout in the Western
Interconnection.\74\ Rather than responding to the Commission's request
for an explanation of why outages on high voltage, non-IROL lines are
unlikely to lead to instability, separation or cascading, NERC and
others simply reiterate their previous rationale. Thus, we conclude
that NERC and other commenters have not adequately supported a
``medium'' Violation Risk Factor designation for Requirement R2.
---------------------------------------------------------------------------

    \73\ NOPR, 141 FERC ] 61,046 at P 77.
    \74\ Id. at PP 78-79.
---------------------------------------------------------------------------

    76. As noted above, a high Violation Risk Factor is defined, in
part, as a ``requirement that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a
cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading
failures * * *'' As we explained in the NOPR, transmission lines that
are not an element of an IROL or Major WECC Transfer Path have
contributed to major cascading outages.\75\ This fact supports a
``high'' Violation Risk Factor designation for Requirement R2.
Moreover, our Violation Risk Factor guidelines, which require, among
other things, consistency within a Reliability Standard (guideline 2)
and consistency between requirements that have similar reliability
objectives (guideline 3), also support modifying the Violation Risk
Factor assigned to Requirement R2 from medium to high.\76\
---------------------------------------------------------------------------

    \75\ NOPR, 141 FERC ] 61,046 at P 78-79.
    \76\ See North American Electric Reliability Corp., 119 FERC ]
61,145 at P 16.
---------------------------------------------------------------------------

    77. Accordingly, we direct NERC to modify the Violation Risk Factor
for Requirement R2 from ``medium'' to ``high,'' within 45 days of the
effective date of the Final Rule.
3. Requirements R1 and R2, Footnote 2--Conditions Outside the
Transmission Owner's Control
    78. Reliability Standard FAC-003-2 includes a footnote describing
certain conditions or scenarios, outside the transmission owner's
control, in which an encroachment would be exempt from Requirements R1
and R2, including natural disasters and certain human or animal
activity.\77\ In its Petition, NERC explained, the footnote ``does not
exempt the Transmission Owner from responsibility for encroachments
caused by activities performed by their own employees or contractors,
but it does exempt them from responsibility when other human
activities, animal activities, or other environmental conditions
outside their control lead to an encroachment that otherwise would not
have occurred.'' \78\
---------------------------------------------------------------------------

    \77\ See Reliability Standard FAC-003-2, n.2.
    \78\ NERC Petition at 23.
---------------------------------------------------------------------------

Comments
    79. Southern Companies and PG&E disagree with the explanation of
footnote 2 in NERC's petition. According to Southern Companies, NERC's
``interpretation'' is contrary to the plain language of the footnote,
which unambiguously states that Requirement R1 ``does not apply to
circumstances that are beyond the control of the Transmission Owner''
including ``human activity'' such as installation, removal, or digging
of vegetation. Southern Companies asserts that the standard drafting
team intended footnote 2, in part, to maintain the exemption from
responsibility for contractor-caused violations provided under the
Version 1 standard. Southern Companies argue that NERC's understanding
could discourage transmission owners from having contractors remove
danger trees from outside of the right-of-way that could make contact
with a conductor since the transmission owner would be responsible for
inadvertent contact during such removal. PG&E makes similar arguments
and adds that, while recognizing that it has a responsibility to ensure
that its employees and contractors are properly trained and follow
appropriate safety practices, a utility cannot craft a vegetation
management program that will prevent unintended and unpredictable
encroachment associated with possible human activity or error. Thus,
Southern Companies and PG&E urge the Commission to reject NERC's
explanation of footnote 2.
    80. BPA comments that it ``understand and accepts'' that
transmission owners will be held liable for the actions of its
employees and contractors, but believes there should be exceptions to
this liability in some circumstances. According to BPA, if for example
employees or contractors are negligent while felling a tree, the
utility should be held accountable. However, BPA maintains that ``an
exemption should be granted'' if a transmission owner can demonstrate
that it utilized appropriate best management vegetation strategies and
practices, but an unpredictable event occurs, such as an equipment
failure, rope breakage or a hidden tree defect, and results in an
encroachment that violates Requirement R1 or R2. BPA notes that placing
liability on the transmission owner will have potentially significant
cost impacts. For example, BPA asserts that vegetation contractors will
have to increase the amounts on their liability insurance and
performance bonds, and pass those costs on to transmission owners.
    81. In reply to Southern Companies and PG&E, NERC states that it
consulted with the standard drafting team in preparing the petition and
confirmed that the intent of footnote 2 was not to exclude the activity
of the employee or contractor. According to NERC, interpreting the
footnote as suggested by Southern Companies and PG&E would insulate all
errors in executing vegetation management plans and ``effectively
encourage mismanagement.'' Rather, according to NERC, specific
instances of error by employees or contractors in executing a
vegetation management plan may be addressed on a case-by-case analysis,
including the scenarios described by BPA.
Commission Determination
    82. The language in footnote 2 of FAC-003-2 provides:

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

    83. The stated intent of the footnote is to not hold transmission
owners responsible for vegetation encroachments into the MVCD resulting
from circumstances beyond the control of the transmission owner. The
footnote then provides numerous examples of circumstances beyond a
transmission owner's control, including ``human or animal activity such
as logging * * * or installation, removal, or digging of vegetation.''
As stated above, NERC explained that footnote 2 ``does not exempt the
Transmission Owner from responsibility for encroachments caused by
activities performed by their own employees or contractors, but it does
exempt them from responsibility when other human activities, animal
activities, or other environmental conditions outside their control
lead to

an encroachment that otherwise would not have occurred.'' \79\
---------------------------------------------------------------------------

    \79\ NERC Petition at 23.
---------------------------------------------------------------------------

    84. We do not read NERC's statement as inconsistent with the
language of the footnote, as suggested by Southern Companies. Footnote
2 does not remove from the responsibility of the transmission owner all
activity of its employees or contractors under all circumstances. We do
not read NERC's statement as ascribing transmission owner
responsibility under Requirements R1 and R2 to all activity of its
employees or contractors. Rather, should an encroachment occur as a
result of activity by a transmission owner's employee or contractor, a
case-by-case analysis is necessary to determine responsibility. This
understanding is consistent with BPA's comments, which recognize that
transmission owners may be held liable for the actions of an employee
or contractor, while also acknowledging that unpredictable events may
occur that are reasonably outside the control of the transmission
owner. We believe that this is an appropriate approach that is
consistent with the text of footnote 2 of FAC-003-2 as well as NERC's
explanation of this provision.
4. Elimination of Training Requirement
    85. Requirement R1.3 of the Version 1 standard provides that
``[a]ll personnel directly involved in the design and implementation of
the TVMP shall hold appropriate qualifications and training, as defined
by the Transmission Owner, to perform their duties * * *'' Reliability
Standard FAC-003-2 does not include a training requirement. According
to NERC, the provision of the Version 1 standard is ``effectively
meaningless,'' since ``appropriate'' qualifications and training are
undefined and left entirely to the discretion of the transmission
owner.\80\
---------------------------------------------------------------------------

    \80\ NOPR, 141 FERC ] 61,046 at P 33 (citing NERC Petition at
31-32).
---------------------------------------------------------------------------

Comments
    86. PA PUC disagrees with the elimination of the training provision
and recommends that the Commission require NERC to develop a standard
that specifies the minimum necessary qualifications and training for
personnel involved in the design and implementation of vegetation
management programs. Washington DNR also urges the Commission to not
approve the elimination of Requirement R1.3 and, rather, define
appropriate qualifications for personnel performing vegetation
management.
Commission Determination
    87. We are not persuaded by the commenters to direct NERC to
include a training or qualifications provision in FAC-003-2. NERC
explained in its petition that the qualifications provision of the
Version 1 standard, Requirement R1.3, is ``effectively meaningless,''
since ``appropriate'' qualifications and training are undefined and
left entirely to the discretion of the transmission owner.\81\ The use
of the term ``appropriate'' in current Requirement R1.3 does not render
this requirement unenforceable. However, if interested entities wish to
pursue development of a future training requirement further with NERC,
they can develop a Standards Authorization Request (SAR) and submit it
to NERC for consideration.
---------------------------------------------------------------------------

    \81\ NERC Petition at 23-24.
---------------------------------------------------------------------------

D. Requirements R1 and R2

1. Consolidation of Reference Material
NOPR Proposal
    88. The Commission, in the NOPR, noted that NERC provided
information from several sources that are useful to an overall
understanding of the intent of FAC-003-2 and how it will be enforced,
including information from NERC's petition, NERC's Guideline and
Technical Basis document, and NERC's May 25, 2012 response to
Commission staff data requests. The NOPR requested comment on whether
NERC should consolidate the reference material so that entities that
must comply can find these materials in one place.\82\
---------------------------------------------------------------------------

    \82\ NOPR, 141 FERC ] 61,046 at P 91.
---------------------------------------------------------------------------

Comments
    89. NERC comments that it does not object to consolidating the
reference material and posting it on the NERC Web site along with FAC-
003-2 prior to implementation. BPA and ITC Companies agree that the
reference material should be consolidated in one place. Trade
Associations comment that the guidance material can have value to
inform a company in developing management plans and activities, but
cautions that such guidance must not alter the requirements of a
Reliability Standard or be used as a compliance measurement.
Commission Determination
    90. NERC and other commenters support the NOPR proposal to
consolidate reference material pertaining to FAC-003-2 to support
implementation of the Reliability Standard. We agree with NERC and
other commenters and adopt our NOPR proposal. Accordingly, within 45
days of the effective date of the Final Rule, NERC must consolidate the
reference material and post it on the NERC Web site along with
Reliability Standard FAC-003-2.
2. Requirement R4--Notification of a Vegetation Condition Likely To
Cause an Imminent Fault
NOPR Proposal
    91. Requirement R4 of FAC-003-2 requires transmission owners to
notify ``without intentional time delay'' the control center with
switching authority for the applicable line when the transmission owner
has confirmed the existence of a vegetation condition that is likely to
cause an imminent fault. In the NOPR, the Commission asked for comment
on how NERC ``would or should treat a delay in communication caused by
the negligence of the transmission owner or one of its employees, where
the delay may be significant and `unintentional.' '' \83\
---------------------------------------------------------------------------

    \83\ NOPR, 141 FERC ] 61,046 at P 92.
---------------------------------------------------------------------------

Comments
    92. NERC responds that the specific facts and circumstances
underlying a delay in communication must be determined on a case-by-
case basis. However, according to NERC, the expectation in Requirement
R4 is that once the transmission owner has confirmed the existence of a
vegetation condition that is likely to cause an imminent fault, the
transmission owner must immediately notify the control center. NERC
explains that the standard drafting team did not include a
``quantitative'' time element for notification in Requirement R4 due to
the difficulty in determining one time period that applies to all
situations.
    93. Trade Associations, Duke and Southern Companies comment that
the inquiry into whether a transmission owner's notification occurred
``without any intentional time delay'' is a fact specific
determination. Southern Companies adds that the drafting team
considered a specific time window for notifying the control center but
adopted the current language because it (i) avoids an arbitrarily
narrow time-frame and (ii) provides a clear metric. PacifiCorp comments
that, because the severity of an event will ``vary across facts and
circumstances,'' it recommends the ``development of a load factor above
which the failure to promptly report a vegetation condition * * * would
warrant a high severity level and below which would warrant a lesser
severity level.'' \84\ Idaho Power comments that the cause of the delay

must be assessed and degrees of failure could be addressed in Violation
Severity Levels or, if delays result from administrative process
issues, addressed in the ``find, fix and track'' process.
---------------------------------------------------------------------------

    \84\ PacifiCorp Comments at 5.
---------------------------------------------------------------------------

Commission Determination
    94. We agree with the explanation of NERC and Trade Associations
that the specific facts and circumstances underlying a delay in
communication must be determined on a case-by-case basis. We also agree
with, and adopt, NERC's explanation that, pursuant to Requirement R4,
once the transmission owner has confirmed the existence of a vegetation
condition that is likely to cause an imminent fault, the transmission
owner must immediately notify the control center.
    95. We reject PacifiCorp's suggestion that severity levels for non-
compliance with Requirement R4 be tied to a load factor. This appears
to be an overly-complex approach to address a failure to promptly
communicate a vegetation condition that is likely to cause an imminent
fault.
3. Reporting Requirements
NOPR Proposal
    96. The Version 1 Standard, FAC-003-1, Requirements R3 and R4,
require quarterly reporting to the Regional Entities of sustained
transmission outages caused by vegetation. In the NOPR, the Commission
explained that, while FAC-003-2 moves the reporting requirements to the
``Additional Compliance Information'' section as a Periodic Data
Submittal, NERC maintains that the reporting requirements remain
enforceable under NERC's Rules of Procedure. In its Petition, NERC
stated that it and Regional Entities can require entities to provide
``such information as is necessary to monitor compliance with the
reliability standards'' under Section 401.3 of NERC's Rules of
Procedure.\85\ NERC asserted that ``it has certain courses of action it
may undertake as necessary to ensure the entity complies with the Rule,
pursuant to NERC Rule of Procedure Section 100, including notifying the
Commission of the entity's failure to comply.\86\ While agreeing that,
pursuant to Section 401.3, NERC and the Regional Entities can require
transmission owners to submit quarterly reports of sustained
transmission outages, the Commission asked for comment regarding the
``courses of action'' that are available to NERC to ensure compliance.
---------------------------------------------------------------------------

    \85\ NOPR, 141 FERC ] 61,046 at P 93. Section 401.3 of NERC's
Rules of Procedure provides, ``all Bulk Power System owners,
operators and users shall provide to NERC and the applicable
Regional Entity such information as is necessary to monitor
compliance with the Reliability Standards.''
    \86\ Id. (citing NERC Petition at 31-32. Section 100 of NERC's
Rules of Procedure provides, ``[e]ach Bulk Power System owner,
operator, and user shall comply with all Rules of Procedure of NERC
that are made applicable to such entities* * *. If NERC determines
that a Rule of Procedure has been violated, or cannot practically be
complied with, NERC shall notify [the Commission] and take such
other actions as NERC deems appropriate to address the situation.'')
---------------------------------------------------------------------------

Comments
    97. NERC responds that, as an example of a course of action, the
NERC Rules of Procedure provide possible consequences for an entity's
failure to timely provide requested data--including application of a
``severe'' Violation Severity Level for a Reliability Standard
Violation.\87\ Idaho Power suggests that other courses of action could
include Regional Entity audits, spot checks and investigations of
vegetation-caused outages.
---------------------------------------------------------------------------

    \87\ NERC Comments at 16 (citing NERC Rules of Procedure, App.
4C (Compliance Monitoring and Enforcement Program), at Att. 1).
---------------------------------------------------------------------------

    98. Santa Clara asserts that non-compliance with the quarterly
reporting requirement is analogous to non-compliance with a NERC
request for data that is necessary to meet NERC's section 215
obligations, pursuant to Section 1600 of NERC's Rules of Procedure.
Santa Clara thus maintains that NERC's only recourse, pursuant to
Section 1603 of NERC's Rules, is to refer such non-compliance to the
Commission for enforcement. According to Santa Clara, the Rules
provisions cited in NERC's Petition and the NOPR are not applicable
because they pertain specifically to NERC's compliance/enforcement
program.
    99. In a reply comment, NERC reiterates its authority under Section
400 of the NERC Rules of Procedure, claiming that the quarterly
reporting obligation is ``squarely'' part of NERC's compliance,
monitoring and enforcement functions.
Commission Determination
    100. We accept NERC's explanation that it has ``tools'' to address
non-compliance with the reporting requirements set forth in the
``Additional Compliance Information'' section of Reliability Standard
FAC-003-2. As NERC indicates, in connection with a substantive
violation of Requirements R1 or R2 of FAC-003-2 due to an encroachment
that causes a sustained outage, NERC or a Regional Entity can attach a
higher Violation Severity Level to that violation based on the failure
to identify the encroachment in a required periodic report. Likewise,
pursuant to the NERC Rules, the Regional Entity can devote more
compliance resources to oversight of an entity that fails to comply
with a reporting requirement.\88\
---------------------------------------------------------------------------

    \88\ See North American Electric Reliability Corp., 141 FERC ]
61,241, at PP 78-83 (2012) (approving NERC's revised Rules of
Procedure, including Section 3.0 and CMEP Attachment 1 that
specifies possible actions in response to an entity that fails to
provide timely responses to an ERO or Regional Entity data request).
---------------------------------------------------------------------------

    101. We are not persuaded by Santa Clara's claims that NERC's
``tools'' do not apply because they pertain specifically to NERC's
compliance/enforcement program. Rather, it is reasonable to view a
transmission owner's failure to provide quarterly data as set forth in
the Additional Compliance Information provision of FAC-003-2 as fitting
within NERC's compliance, monitoring and enforcement function. The
reporting of sustained outages caused by vegetation encroachment
pertains to substantive compliance with the requirements of FAC-003-2
and will provide information that is necessary to monitor compliance
with FAC-003-2 to the extent that transmission owners do not otherwise
self-report possible violations. Thus, we find that the reporting of
quarterly data set forth in the Additional Compliance Information
provision falls within Section 401.3 of NERC's Rules of Procedure.
Moreover, NERC's ``tool'' of assigning a higher violation severity
level for a related violation of FAC-003-2 will occur in a compliance
posture. The other ``tool'' identified by NERC, more stringent
oversight of an entity that fails to comply with a reporting
requirement, is simply a matter of Regional Entity discretion regarding
how it chooses to apply compliance resources.
    102. Ultimately, if these tools prove ineffective in gaining the
cooperation of a transmission owner in timely reporting of sustained
outages as set forth in FAC-003-2, NERC's Rules of Procedure provide
for NERC seeking enforcement action by the Commission for a violation
of NERC's Rules of Procedure. Such a violation would also violate
section 39.2 of the Commission's regulations.\89\
---------------------------------------------------------------------------

    \89\ 18 CFR 39.2 (2012).
---------------------------------------------------------------------------

E. Definition of Right-of-Way

    103. NERC modified the definition of ``Right-of-Way'' as follows:

    The corridor of land under a transmission line(s) needed to
operate the line(s). The width of the corridor is established by
engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance

records, or by the blowout standard in effect when the line was
built. The ROW width in no case exceeds the Transmission Owner's
legal rights but may be less based on the aforementioned criteria.

    104. While the Commission in the NOPR proposed to approve the
right-of-way definition, it also sought comment on certain aspects of
the definition. Below, we discuss the following matters related to the
right-of-way definition: (1) Guidance for defining an appropriate
right-of-way; (2) NERC's approach to fall-ins by ``danger trees''; and
(3) vegetation management strategies.
1. Guidance for Defining an Appropriate Right-of-Way
NOPR
    105. In the NOPR, the Commission observed that, because fall-ins,
blow-ins and grow-ins that cause a sustained outage violate FAC-003-2
only if they occur from inside the right-of-way, transmission owners
have an incentive to define right-of-way as narrowly as possible to
limit penalty exposure.\90\ Related, the Commission noted that the
right-of-way definition includes guidance as to how the transmission
owner may define its right-of-way, requiring that it be based on
construction documents, pre-2007 vegetation maintenance records, or as-
built blowout standards. The Commission asked for comment on how the
guidance in the definition will be used by (1) transmission owners to
establish criteria to determine an appropriate right-of-way and (2)
auditors to establish criteria to determine compliance with the
Reliability Standard.\91\
---------------------------------------------------------------------------

    \90\ NOPR, 141 FERC ] 61,046 at P 97.
    \91\ NOPR, 141 FERC ] 61,046 at P 102.
---------------------------------------------------------------------------

Comments
    106. NERC points out that ``an encroachment due to vegetation
growth into the MVCD that caused a vegetation-related Sustained
Outage'' would violate Requirements R1 and R2, ``regardless of the
defined right-of-way.'' \92\ NERC also comments that, given the
significant cost and public scrutiny of a sustained outage,
transmission owners have an incentive to set right-of-way widths
properly to ensure that the land needed to operate a transmission line
is included.
---------------------------------------------------------------------------

    \92\ NERC Comments at 16-17 (emphasis in original) (citing
Reliability Standard FAC-003-2, Requirements R1(4) and R2(4)).
---------------------------------------------------------------------------

    107. Further, NERC clarifies that the right-of-way definition
requires that the width of a corridor ``be established by engineering
or construction standards as documented in either construction
documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built.'' \93\ NERC thus explains
that the three types of information identified in the right-of-way
definition are the criteria for a transmission owner to set the width
of the right-of-way using sound engineering or construction standards.
NERC states that ``in all cases'' the width of the right-of-way must
meet engineering or construction standards and cannot be arbitrarily
set by the transmission owner. According to NERC, auditors will be able
to request supporting information used to set the width of the right-
of-way, including any of the available information listed in the right-
of-way definition.
---------------------------------------------------------------------------

    \93\ NERC Comments at 20. See also BPA Comments at 5.
---------------------------------------------------------------------------

    108. Duke comments that the Commission's concern is unfounded
because transmission owners are not free to arbitrarily define a
particular right-of-way but, rather, are bounded by the specific
parameters stated in NERC's definition.
    109. Trade Associations state that, in many instances, transmission
owners may not have construction documents, pre-2007 vegetation
maintenance records, or as-built blowout standards since many
transmission lines were constructed decades ago and the guidance
material is no longer available. Trade Associations ask the Commission
to clarify that, when guidance materials are unavailable, a
transmission owner may work with NERC and its Regional Entity on a
case-by-case basis to develop right-of-way widths applying, for
example, recognized industry procedures. AEP comments that it supports
the right-of-way definition with the understanding that, for some
lines, the right-of-way may be constrained by the original design or
existing legal rights. ITC also supports clarification where the
materials stated in the right-of-way definition are not available, and
proposes specific language to insert within the definition that would
require the transmission owner to develop a written procedure to
determine and document the corridor width based on current industry
accepted methods.
    110. In its reply comments, NERC opposes ITC's proposal for
specific changes to the right-of-way definition, contending that the
definition includes the necessary latitude for a transmission owner to
determine a right-of-way based on the options provided in the
definition.
Commission Determination
    111. We agree with NERC that an encroachment due to vegetation
growth into the MVCD that results in a sustained outage would violate
Requirements R1 and R2 regardless of the defined right-of-way. This
responsibility is stated explicitly and without qualification regarding
tree location: ``[e]ach Transmission Owner shall manage vegetation to
prevent encroachments into the MVCD of its applicable line(s) * * * of
the types shown below * * * (4) An encroachment due to vegetation
growth into the MVCD that caused a vegetation-related Sustained
Outage.'' \94\ Further, we agree with NERC and others that the criteria
set forth in the right-of-way definition provide a reasonable,
objective means of determining an appropriate right-of-way width.
---------------------------------------------------------------------------

    \94\ Reliability Standard FAC-003-2, Requirement R1, subsection
(4).
---------------------------------------------------------------------------

    112. With regard to the concern of Trade Associations and others
where none of the records mentioned in the right-of-way definition are
available for a specific applicable transmission line, an alternative
approach to setting right-of-way width is necessary. We agree with NERC
that ``in all cases'' the width of the right-of-way must meet
engineering or construction standards and cannot be arbitrarily set by
the transmission owner. As suggested by Trade Associations, one
reasonable way to achieve this is for the transmission owner to work
with NERC and the relevant Regional Entity on a case-by-case basis to
develop right-of-way widths applying recognized industry procedures.
Further, NERC may determine--after some experience with setting right-
of-way widths--that this is an appropriate topic for an industry
advisory or operating committee guideline. We will not, however,
require that NERC revise the Reliability Standard to address this
issue, as suggested by ITC.
2. NERC Approach to Fall-Ins by ``Danger Trees''
NOPR
    113. In the NOPR, the Commission agreed with NERC that fall-ins of
green or healthy trees outside the corridor-based right-of-way, but
within the right-of-way controlled by the transmission owner, would not
violate FAC-003-2. The Commission, however, questioned NERC's approach
to a fall-in by ``danger timber'' in that same range. NERC explained
that, ``if the TO is regularly identifying its danger trees and has a
program for managing the risk of fall-in

there would be no violation.'' \95\ The Commission expressed concern
that this statement ``could be read to mean that, as long as the
transmission owner identifies danger trees and has a program to manage
the risk of those trees, an encroachment into the MVCD from a location
within the transmission owner's control would not be a violation.'')
\96\ The Commission disagreed with such an approach because the mere
existence of a program to identify danger trees and a program to manage
risk should not shield a transmission owner from enforcement.
---------------------------------------------------------------------------

    \95\ NOPR, 141 FERC ] 61,046 at P 101 (citing NERC Data
Responses, Responses to Q9 (May 25, 2012)).
    \96\ NOPR, 141 FERC ] 61,046 at P 101.
---------------------------------------------------------------------------

Comments
    114. In response to the Commission's concerns, NERC clarifies that
its earlier statement that ``if the TO is regularly identifying its
danger trees and has a program for managing the risk of fall-in there
would be no violation'' is accurate so long as the transmission owner
implements a well-managed and executed vegetation management program as
documented under Requirement R3 and as carried out through the risk-
based Requirements R6 and R7. According to NERC, the reference to ``no
violation'' pertained to Requirements R6 and R7, but was not intended
to convey that mere existence of a program to identify danger trees and
a program to manage risk would create a shield from a finding of a
violation under Requirements R1 or R2 if an encroachment occurs.
    115. APS, BPA, PA PUC and VELCO support NERC's approach. They agree
that the ``mere existence'' of a danger tree program is insufficient,
and transmission owners should have a ``demonstrably active and
robust'' danger tree management program. BPA adds that a transmission
owner that has reasonably implemented a program to manage fall-in risks
should be exempt from violation since ``accidents do occur'' even when
due care is exercised. PA PUC comments that, while NERC's data request
response is helpful, it should be incorporated into the BES definition
or the Reliability Standard to prevent confusion in the future.
    116. Trade Associations articulate their understanding that, in the
event of encroachment into the MVCD by a danger tree located outside
the right-of-way but within the control of the transmission owner, the
transmission owner would not be found in violation of Requirement R6
when it implemented a program that regularly identifies danger trees
and manages the risk of fall-in encompassing areas within the
transmission owner's control. Further, Trade Associations comment that,
while it is common practice to include identification and mitigation of
danger trees in transmission owner vegetation management plans, in many
cases the identification of diseased or dying trees is not a matter
involving simple observation.\97\ Thus, Trade Associations as well as
Duke caution against basing enforcement decisions on ``post hoc''
analyses of whether a transmission owner correctly identified a dead or
diseased tree. They assert that, if the Commission places transmission
owners at risk of violation based on such after-the-fact assessment,
transmission owners may likely engage in more clear-cutting to avoid
the risk. VELCO also indicates that a strict stance on off-corridor
danger tree management could lead to more clear-cutting and adds that a
better outcome motivates transmission owners to actively identify and,
exercising professional judgment, remove danger trees on a case-by-case
basis.
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    \97\ Trade Associations note that ANSI A-300 defines ``danger
tree'' as ``a tree on or off the right-of-way that could contact
electric supply lines''; and defines ``hazard tree'' as ``a
structurally unsound tree that could strike a target when it
fails.''
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    117. PacifiCorp maintains that the Commission's concern appears to
be unfounded based on the explicit language of Requirements R1 and R2
that require transmission owners to manage vegetation to prevent all
encroachments into the MVCD of an applicable line, and then identifies
specific circumstances. According to PacifiCorp, the NERC drafting team
was concerned that many transmission owners have rights-of-way far
wider than necessary to responsibly maintain the integrity of their
applicable transmission lines. PacifiCorp asserts that it would be
unreasonable to hold utilities to the same level of compliance for all
activities within the legal right-of-way for areas beyond those
currently necessary.
Commission Determination
    118. Fall-ins of danger trees into the MVCD from outside the right-
of-way but within the control of the transmission owner are not
addressed by Requirements R1 and R2. However, such fall-ins do have
compliance implications with regard to Requirements R6 and R7 of FAC-
003-2. Requirement R6 requires each transmission owner to perform a
``Vegetation Inspection of 100% of its applicable transmission lines *
* * at least once per calendar year * * * '' NERC defines the term
``Vegetation Inspection'' as ``[t]he systematic examination of
vegetation conditions on a Right-of-Way and those vegetation conditions
under the Transmission Owner's control that are likely to pose a hazard
to the line(s) prior to the next planned maintenance or inspection * *
* '' \98\ The definition explicitly provides that the Vegetation
Inspection include the examination of vegetation conditions not only in
the defined right-of-way but of ``vegetation conditions under the
Transmission Owner's control that are likely to pose a hazard to the
line(s) * * * '' Likewise, Requirement R7 provides that ``[e]ach
transmission owner shall complete 100% of its annual vegetation work
plan of applicable lines to ensure no vegetation encroachments occur
within the MVCD,'' without mention of or limitation to the defined
right-of-way.\99\
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    \98\ NERC Petition at 2 (emphasis added).
    \99\ Reliability Standard FAC-003-2, Requirement R7. The
Guideline and Technical Basis contained in FAC-003-2 also indicates
that the annual work plan is not limited to the right-of-way: ``[i]n
general, the vegetation management maintenance approach should use
the full extent of the Transmission Owner's easement, fee simple and
other legal rights allowed.'' Id. at 24.
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    119. Thus, the fall-in of danger tree from outside the defined
right-of-way but within a transmission owner's control would likely
merit examination to determine whether the transmission owner is
properly conducting the annual Vegetation Inspection as required by
Requirement R6 and performing the annual work plan as required by
Requirement R7. In this context, we find the explanation of NERC and
other commenters informative that it is not sufficient for a
transmission owner simply to demonstrate that it identifies danger
trees and has a program for managing the risk of fall-in. Rather, a
transmission owner must have a well-managed, danger tree management
program as carried out through Requirements R6 and R7.\100\
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    \100\ NERC Comments at 19-20.
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    120. As indicated by NERC, the ``documented maintenance
strategies'' required by Requirement R3 should demonstrate whether a
transmission owner adequately inspects vegetation and completes its
annual work plan. Likewise, the Measures set forth in FAC-003-2 provide
the basis for determining a transmission owner's compliance with the
corresponding Requirements R6 and R7. We agree with Trade Associations
and Duke that a potential violation of Requirements R6 and R7 should
not be based on ``post

hoc'' analyses of whether a transmission owner correctly identified a
dead or diseased tree. A fall-in from outside of the defined right-of-
way may give reason to review a transmission owner's compliance with
the annual inspection and work plan requirements. In the context of
fall-ins from outside the defined right-of-way, enforcement decisions
should be based on a review of the quality of the transmission owner's
program and its execution of that program.
3. Vegetation Management Strategies
NOPR
    121. In the NOPR, the Commission noted that FAC-003-2 does not
require clear-cutting along the right-of-way but, instead, gives the
transmission owner flexibility to adopt an appropriate vegetation
management strategy to comply with the Reliability Standard. The NOPR
also noted that NERC's Technical Reference Document provides that
different vegetation management strategies may be appropriate for
different areas, and FAC-003-2 gives transmission owners the option to
adopt strategies to comply with FAC-003-2 that encourage active
vegetation management and Integrated Vegetation Management rather than
clear-cutting.\101\ Further, NERC's Technical Reference Document
describes American National Institute of Standards (ANSI) A-300--Best
Management Practices for Tree Care Operations and identifies Integrated
Vegetation Management as a best management practice, including
incorporation of wire-border zone management techniques and the
establishment and maintenance of compatible vegetation.
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    \101\ NOPR, 141 FERC ] 61,046 at P 100 (citing NERC Petition,
Ex. I (Technical Reference Document) at 24-29).
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Comments
    122. Trade Associations state that, since approval of FAC-003-1,
transmission owners have ``aggressively pursued compliance under a
`zero defects' mandate for transmission tree-related outages'' and, as
a result, only a small number of violations have affected reliable
operation of the Bulk-Power System.\102\ According to Trade
Associations, transmission owners' vegetation management practices are
designed to prevent vegetation-related outages by creating and
sustaining a stable and compatible ``vegetated community'' within a
transmission corridor using ``integrated vegetation management''
techniques. They further explain that vegetation that has the ``genetic
disposition'' to grow to heights that may interfere with transmission
should be removed. Trade Associations contend that continuous trimming
will not guarantee that an encroachment will not occur, and it is a
``gamble'' not to use best management practices and remove the
vegetation that will interfere with transmission. They add that
transmission owners do have successful vegetation management programs
that also help property owners maintain and even enhance the
environmental benefits of the right-of-way while ensuring sufficient
clearance between the vegetation and energized conductors. Trade
Associations and ITC add that transmission owners have outreach
programs and maintain information on company Web sites on vegetation
management practice, and encourage the Commission to further this
public education process. PacifiCorp suggests that the Commission
appears to apply a ``double standard'' by supporting a zero tolerance
approach to compliance with FAC-003 while also opposing tree removal.
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    \102\ Trade Association Comments at 13. See also ITC Comments at
6-7.
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    123. PG&E and APS support the Commission's recognition of the
importance of using best utility vegetation management practices, the
use of Integrated Vegetation Management and the ``wire-border zone''
technique contained in ANSI A-300. PG&E states that an approach using
these concepts will accomplish the objective of developing and
maintaining a sustainable, low-growing compatible plant community in
the right-of-way, while reducing the risk of vegetation-related
outages. APS states that ANSI A-300 recognizes the need to remove
vegetation that can cause power outages within the right-of-way and to
convert the right-of-way to more compatible plant species.
    124. APS comments that ANSI A-300 recognizes the need to
communicate with all stakeholders involved in the vegetation
maintenance process. APS acknowledges that the Commission ``is in a
difficult position'' on ensuring reliability and considering public
expectations for vegetation management.\103\ APS recognizes that, in
the past, transmission owners have used the Commission's regulations as
an ``excuse'' for clearing trees. According to APS, while properly
implementing best management practices may require clearing that could
displease property owners, vegetation management programs should engage
and work cooperatively with land owners.
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    \103\ APS Comments at 8.
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    125. Trade Associations also raise concerns regarding right-of-way
access issues, particularly involving federal lands. According to Trade
Associations, for some transmission owners, access to federal lands is
a ``significant variable'' in setting facilities ratings, configuring
transmission for reliability and vegetation management. Trade
Associations assert that, particularly in Western states, transmission
owners have experienced significant difficulties with federal agency
field personnel for obtaining timely permission to access land and
scheduling facilities inspections and maintenance activities, including
vegetation management. Trade Associations thus urge the Commission to
take a leadership role in initiating and coordinating discussions with
other federal agencies, and with stakeholder groups, to find practical
remedies to right-of-way access issues.
Commission Determination
    126. As indicated by NERC, Requirement R3 documented maintenance
strategies can take many forms.\104\ While accommodating flexibility,
these documented strategies must have sufficient specification to
provide a means to follow the transmission owner's strategy through a
paper trail or guidelines. Documented strategies cannot be so vague as
to fail to provide any clear guidance for auditors and others to
understand the basis for the transmission owner's vegetation management
program.
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    \104\ NERC Petition at 17, 20, 35.
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    127. With regard to comments on the implementation of vegetation
management strategies, we agree that ANSI-A 300 is a commonly
recognized source for best vegetation management practices. We disagree
with PacifiCorp, however, that we are seeking to apply a ``double
standard'' by supporting a zero tolerance approach to compliance with
FAC-003 while also opposing tree removal. We understand that, as
explained by Trade Associations and other commenters, best practices
call for the removal of tall-growing vegetation from the right-of-way
and replacement with a sustainable plant community. In many
circumstances, this is a reasonable approach. However, we also believe
that a transmission owner should not monolithically equate vegetation
management with tree removal. Circumstances may provide greater
latitude, for example, when addressing the concerns of an individual
landowner and where the species of vegetation are not genetically
disposed

to encroach into the MVCD. Certainly, as recognized by APS, a
transmission owner decision's to remove vegetation in such
circumstances should not be ascribed to the Commission.
    128. Ultimately, transmission owners should work with private land
owners to determine an appropriate approach that assures reliability
and respects private land owner concerns. As noted by commenters, this
approach requires clear communications between transmission owners and
private landowners; and meaningful outreach should indicate how a
transmission owner plans to execute vegetation management along the
right-of-way.
    129. Trade Associations raise concerns regarding transmission
owners' right-of-way access issues on public lands. We note that in
Order No. 693, the Commission directed NERC ``to collect outage data
for transmission outages of lines that cross both federal and non-
federal lands, analyze it, and use the results of this analysis and
information to develop a Reliability Standard that would apply to
transmission lines crossing both federal and non-federal land.'' \105\
NERC has not provided this analysis, nor does the development record
provided with NERC's petition indicate that the standard drafting team
utilized such analysis or data in developing FAC-003-2. In these
circumstances, given the lack of objective data, it is difficult for
the Commission to gauge the nature or seriousness of this issue.
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    \105\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 732.
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    130. NERC should gather and analyze the necessary data regarding
vegetation management issues on public lands. If NERC's analysis
indicates that there are issues that should be addressed, NERC should
propose a means to address the concern, for example by issuing an
alert, or propose other appropriate action.

III. Information Collection Statement

    131. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\106\ Upon approval of a
collection(s) of information, OMB will assign an OMB control number and
expiration date. Respondents subject to the filing requirements of this
rule will not be penalized for failing to respond to these collections
of information unless the collections of information display a valid
OMB control number.
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    \106\ 5 CFR 1320.11.
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    132. The Commission is submitting these reporting and recordkeeping
requirements to OMB for its review and approval under section 3507(d)
of the Paperwork Reduction Act of 1995. The Commission solicited
comments on the need for and the purpose of the information contained
in Reliability Standard FAC-003-2 and the corresponding burden to
implement the Reliability Standard. The Commission received one comment
on the reporting burden estimates. Idaho Power states that it does not
anticipate adding new transmission lines to its vegetation management
plan and, therefore, Idaho Power does not project a significant
increase in outage reporting.
    133. The Final Rule approves Reliability Standard FAC-003-2, which
includes certain requirements to create and maintain records related to
a transmission owner's vegetation management strategies, vegetation
management work plan and its performance of inspections. Because
transmission owners have vegetation management plans they follow per
the existing transmission vegetation management standard (FAC-003-1),
and must compile and maintain similar records and provide similar
reports under the existing standard, the revisions are expected to have
a minor impact on the burden of record-keeping and reporting. In
addition, by allowing greater flexibility compared to the currently-
effective Version 1 standard with regard to the materials that must be
maintained for a vegetation management plan or strategy, FAC-003-2 may
reduce the reporting burden for some entities.
    134. Public Reporting Burden: Our estimate below regarding the
number of respondents is based on the NERC compliance registry as of
July 24, 2012. According to the compliance registry, NERC has
registered 330 transmission owners within the United States.
Transmission owners must report and retain certain data pursuant to the
currently effective Version 1 standard. Thus, the burden estimate below
is based on the potential change in the reporting burden imposed by
FAC-003-2. Requirement R3 of FAC-003-2 provides more flexibility than
FAC-003-1 for transmission owners in preparing and maintaining a
vegetation management program, and the incremental change in the burden
may be negligible or even decrease for some portion of transmission
owners. The individual burden estimates are based on each transmission
owner having to perform a one-time review of the revised Reliability
Standard's information collection requirements and to make any required
modifications to its existing vegetation management plans and
documentation procedures. In addition, the burden estimate takes into
account an on-going, albeit very minor increase in the quarterly
reporting burden, based on the increased burden to confirm whether or
not reportable outages have occurred on lines not previously subject to
FAC-003-1's requirements. Idaho Power's comment affirms that the
increase in quarterly reporting burden should be insignificant.
Further, the burden estimate takes into account the increased
recordkeeping burden associated with the Reliability Standard's annual
vegetation inspection requirements, which is estimated to increase the
inspection cycles (and the associated documentation to demonstrate
compliance) for about one third of transmission owners (110
transmission owners).

----------------------------------------------------------------------------------------------------------------
                                                    Number of
                                                  transmission      Number of     Average burden   Total annual
 FAC-003-2 (transmission vegetation management)       owner       responses per     hours per      burden hours
                                                   respondents     respondent        response
                                                            (1)             (2)            (3)       (1) x (2) x
                                                                                (3)
----------------------------------------------------------------------------------------------------------------
One time review and modifications to existing               330               1             16             5,280