Revisions to Reliability Standard for Transmission Vegetation Management, 18817-18837 [2013-07113]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 78, Number 60 (Thursday, March 28, 2013)]
[Rules and Regulations]
[Pages 18817-18837]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[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

[[Page 18818]]

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: (301) 665-1391.
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: (202) 502-8529.
Julie Greenisen (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, Telephone: (202) 502-6362.

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 https://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 https://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.

[[Page 18819]]

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: https://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-

[[Page 18820]]

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

[[Page 18821]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 18822]]

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

[[Page 18823]]

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

[[Page 18824]]

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

[[Page 18825]]

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.

[[Page 18826]]

* * * 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

[[Page 18827]]

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

[[Page 18828]]

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

[[Page 18829]]

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

[[Page 18830]]

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

[[Page 18831]]

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.
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \100\ NERC Comments at 19-20.
---------------------------------------------------------------------------

    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

[[Page 18832]]

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.
---------------------------------------------------------------------------

    \101\ NOPR, 141 FERC ] 61,046 at P 100 (citing NERC Petition, 
Ex. I (Technical Reference Document) at 24-29).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \102\ Trade Association Comments at 13. See also ITC Comments at 
6-7.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \103\ APS Comments at 8.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \104\ NERC Petition at 17, 20, 35.
---------------------------------------------------------------------------

    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

[[Page 18833]]

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.
---------------------------------------------------------------------------

    \105\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 732.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \106\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    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
 documentation, plans and procedures...........                                                       (one-time)
Quarterly Reporting............................       \107\ 115               4              0.5             230
Annual Vegetation Inspections Documentation....             110               1              2               220
                                                ----------------------------------------------------------------

[[Page 18834]]

 
    Total......................................  ..............  ..............  ...............           5,730
----------------------------------------------------------------------------------------------------------------
\107\ While approval of FAC-003-2 is not expected to increase the number of reports made or the number of
  reportable outages experienced, some utilities may experience a slight increase in the amount of time required
  to confirm whether or not any reportable outages occurred due to the increased applicability of the standard
  to certain sub-200 kV transmission lines.

    Total Annual Hours for Collection: (Compliance/Documentation) = 
5,730 hours.
    Quarterly Reporting Cost for Transmission Owners: = 230 hours @ 
$70/hour \108\ = $16,100.
    Annual Vegetation Inspections Documentation: = 220 hours @ $28/hour 
\109\ = $6,160.
---------------------------------------------------------------------------

    \108\ This figure is the average of the salary plus benefits for 
a manager and an engineer. The figures are taken from the Bureau of 
Labor and Statistics Web site at https://bls.gov/oes/current/naics3_221000.htm.
    \109\ Wage figure is based on a Commission staff study of record 
retention burden.
---------------------------------------------------------------------------

    Total Annual Cost (Reporting + Record Retention): = $16,100 + 
$6,160 = $22,260.
    One-Time Review and Modification of Plans and Documentation: 5,280 
hours @ $52/hour \110\ = $274,560.
---------------------------------------------------------------------------

    \110\ This figure is the average of the salary plus benefits for 
an engineer and a forester. The figures are taken from Bureau of 
Labor and Statistics Web site at https://bls.gov/oes/current/naics3_221000.htm.
---------------------------------------------------------------------------

    Title: Mandatory Reliability Standards for the Bulk-Power System.
    Action: Revisions to collection FERC-725A.
    OMB Control No.: 1902-0244.
    Respondents: Businesses or other for-profit institutions; not-for-
profit institutions.
    Frequency of Responses: Annual, quarterly, and one-time.
    Necessity of the Information: Reliability Standard FAC-003-2 
Transmission Vegetation Management is part of the implementation of the 
Congressional mandate of the Energy Policy Act of 2005 to develop 
mandatory and enforceable Reliability Standards to better ensure the 
reliability of the nation's Bulk Power System. Specifically, the 
revised standard would ensure that transmission owners are protecting 
transmission lines from encroachment of vegetation.
    Internal Review: The Commission has reviewed the revisions to the 
currently-effective Reliability Standard and made a determination that 
its action is necessary to implement section 215 of the FPA. The 
Commission has assured itself, by means of its internal review, that 
there is specific, objective support for the burden estimate associated 
with the information requirements.
    135. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director, email: 
DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].
    For submitting comments concerning the collection(s) of information 
and the associated burden estimate(s), please send your comments to the 
Commission and to the Office of Management and Budget, Office of 
Information and Regulatory Affairs, Washington, DC 20503 [Attention: 
Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 
395-4638, fax: (202) 395-7285]. For security reasons, comments to OMB 
should be submitted by email to: oira_submission@omb.eop.gov. Comments 
submitted to OMB should include OMB Control Number 1902-0244 and Docket 
Number RM12-4-000.

IV. Environmental Analysis

    136. The Commission is required to prepare an Environmental 
Assessment (EA) or an Environmental Impact Statement (EIS) for any 
action that may have a significant adverse effect on the human 
environment.\111\ The Commission has categorically excluded certain 
actions from this requirement as not having a significant effect on the 
human environment. In the NOPR, the Commission stated the proposed 
action, i.e., approval of the revised Reliability Standard, falls 
within the categorical exclusion for rules that are clarifying, 
corrective, or procedural, or that do not substantially change the 
effect of the regulations being amended.\112\
---------------------------------------------------------------------------

    \111\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
Regulations Preambles 1986-1990 ] 30,783 (1987).
    \112\ See NOPR, 141 FERC ] 61,046 at P 116 (citing 18 CFR 
380.4(a)(2)(ii)).
---------------------------------------------------------------------------

Comments
    137. Washington DNR urges the Commission to perform an EIS on 
Reliability Standard FAC-003-2. According to Washington DNR, vegetation 
management can conflict with protection of fragile vegetation species 
that are identified in federal and state programs and, thus, changes to 
the Reliability Standard may result in adverse environmental impacts. 
Washington DNR comments that it cannot fully assess the impacts of the 
proposed Reliability Standard since it is unaware of the locations of 
all transmission lines operated below 200 kV that would be subject to 
FAC-003-2 and may affect state lands. Washington DNR contends that the 
proposed Commission rulemaking constitutes a major federal action with 
the potential for significant impacts on the environment and must not 
be promulgated without an EIS. Washington DNR disagrees with the 
Commission's reliance on the categorical exclusion for rules that are 
clarifying, corrective, or procedural, or do not substantially change 
the effect of regulations being amended. Rather, according to 
Washington DNR, the proposal substantively changes the existing 
regulations by ``applying expanded clearance standards and an entirely 
new and legally indefensible definition of `right-of-way', and does so 
across unpublished miles of under-200 kV line not currently subject to 
this regulation.'' \113\
---------------------------------------------------------------------------

    \113\ Washington DNR Comments at 3.
---------------------------------------------------------------------------

    138. Washington DNR also contends that the timeframe to comply with 
the Version 2 standard does not include sufficient time for 
transmission owners to give meaningful notice to landowners, obtain 
relevant information about the environmental characteristics or 
management of adjacent lands, obtain permits, and work with landowners 
to create mutually agreed upon management plans.
    139. APS and PacifiCorp recommend that the Commission initiate an 
EIS in conjunction with other federal agencies such as the U.S. 
Department of Agriculture, U.S. Department of Interior and DOE. 
According to APS, because the Version 1 standard ``compelled 
transmission owners to determine what should be appropriate for 
vegetation

[[Page 18835]]

management, the industry automatically referenced ANSI A-300 Best 
Management Practices for Tree Care Operations.'' \114\ APS claims that 
the elimination of a direct reference to ANSI A-300 will ``lead to weak 
links'' and possibly result in some transmission owners regressing in 
their vegetation management programs by reverting to tree pruning. 
Thus, APS recommends that an EIS address implementation of ANSI A-300 
and applicable best management practices on federal lands to ``provide 
transmission owners authority and allow them to define their program of 
work within the scope of their TVMP and eliminate personal opinion when 
working at the local level of each federal agency.''\115\
---------------------------------------------------------------------------

    \114\ APS Comments at 5.
    \115\ Id. at 6.
---------------------------------------------------------------------------

Commission Determination
    140. The Commission is required to prepare an EA or an EIS for any 
action that may have a significant adverse effect on the human 
environment.\116\ We disagree with the assertion that we should require 
an EIS or EA for Reliability Standard FAC-003-2.
---------------------------------------------------------------------------

    \116\ Order No. 486, FERC Stats. & Regs. ] 30,783.
---------------------------------------------------------------------------

    141. Reliability Standard FAC-003-2 modifies the currently 
effective Version 1 standard. For example, it includes minimum 
vegetation clearance distances in the text of the standard, instead of 
referencing another document as in the Version 1 standard. However, the 
revised standard makes little change in minimum clearance distance 
values from the current rule and, therefore, will not have a 
significant impact on how transmission owners currently perform 
vegetation management so as to warrant an EA or EIS. The differences in 
minimum clearance distances between FAC-003-2 and the Version 1 
standard are measured in inches, and thus do not give rise to concerns 
that the modified standard may have a significant adverse effect on the 
human environment.\117\
---------------------------------------------------------------------------

    \117\ See May 23, 2012, NERC Comments on PNNL Report, Att. A at 
5, identifying the ``additional distance afforded by MVCD'' for a 
115 kV transmission line as 2.52 inches; the greatest difference 
shown for a 500 kV line is 14.04 inches.
---------------------------------------------------------------------------

    142. Further, we are not persuaded by Washington DNR that NERC's 
revised definition of the term ``Right-of-Way'' justifies undertaking 
an EA or EIS. Version 1 defines right-of-way based on a transmission 
owner's legal rights.\118\ In Order No. 693, the Commission directed 
NERC to consider whether to change the definition of right-of-way to 
more precisely define the area that needed to be subject to vegetation 
management, i.e., to encompass the required clearance area, and not the 
entire legal right-of-way, particularly where the legal right-of-way 
may greatly exceed the area needed for effective vegetation 
management.\119\ The revised right-of-way definition submitted with 
FAC-003-2 recognizes that a transmission owner may not always need to 
maintain vegetation to the full extent of its legal right-of-way. For 
example, PacifiCorp explains that a transmission owner may have 
acquired rights in anticipation of adding facilities at a later date, 
but maintenance of the additional corridor may not be necessary to 
assure that vegetation will not encroach into existing transmission 
lines.\120\ The new FAC-003-2 would allow transmission owners 
flexibility to manage vegetation in an area less than their legal 
right-of-way but still in an area appropriate to assure no encroachment 
into a transmission line. Other than pointing to the fact that NERC 
revised the right-of-way definition, Washington DNR provides no 
explanation how bringing more precision to the area that needs to be 
managed in the new right-of-way definition may have a significant 
adverse effect on the human environment.
---------------------------------------------------------------------------

    \118\ NERC's Version 1 ROW definition provides:
    A corridor of land on which electric lines may be located. The 
Transmission Owner may own the land in fee, own an easement, or have 
certain franchise, prescription, or license rights to construct and 
maintain lines.
    \119\ NOPR, 141 FERC ] 61,046 at P 16.
    \120\ PacifiCorp comments at 7.
---------------------------------------------------------------------------

    143. The application of the standard to certain sub-200 kV 
facilities under the revised standard also does not warrant the 
preparation of an EA or EIS. While the expanded applicability subjects 
the owners of certain sub-200 kV transmission facilities to compliance 
with FAC-003-2, we do not expect the expanded applicability of FAC-003-
2 to significantly change vegetation management practices at these 
facilities or otherwise have a significant adverse effect on the human 
environment. The transmission lines that are implicated by FAC-003-2, 
even under the expanded applicability, by necessity, are currently 
subject to vegetation management practices, as transmission owners must 
maintain their existing rights-of-way to prevent flashovers and 
outages.\121\ In many instances, utilities manage vegetation to comply 
with either good utility practice or conduct vegetation management in 
accordance with best industry practices.\122\
---------------------------------------------------------------------------

    \121\ A 2004 study provided information on clearance distances 
maintained by utilities for sub-230 kV transmission lines. A 
comparison of this data with the minimum clearance distances for 
sub-200 kV transmission lines set forth in FAC-003-2 indicates that, 
historically, the vast majority of utilities have cleared vegetation 
to greater distances than the minimum values set forth in the 
standard. See Utility Vegetation Management and Bulk Electric 
Reliability Report from the Federal Energy Regulatory Commission, 
Sept. 2004, p. 11, Table 4 (Vertical Clearances Reported).
    \122\ E.g., ANSI A-300--Best Management Practices for Tree Care 
Operations.
---------------------------------------------------------------------------

    144. Moreover, while the revised Reliability Standard requires a 
specific result, i.e., that vegetation does not encroach into the MVCD, 
the standard does not require any specific means of obtaining that 
result. Transmission owners will have flexibility regarding how they 
perform vegetation management to comply with the new standard, and the 
circumstances (topography, weather, tree growth, etc.) will differ for 
each transmission owner.\123\ Thus, while we believe that the impacts 
will not be significant because transmission owners have generally 
conducted vegetation management on the sub-230 kV facilities that will 
now be subject to compliance with FAC-003-2 (or else there would have 
been many more flashovers and outages), identifying those incremental 
impacts of the revised Reliability Standard on either a programmatic or 
site-specific basis would be difficult and likely not produce 
meaningful results. In such circumstances, where the potential impacts 
are not subject to meaningful quantification, courts have found that it 
is not necessary to conduct an EIS or EA.\124\
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    \123\ In certain circumstances, transmission owners will 
negotiate the vegetation management activities they undertake to 
comply, also showing that the new standard does not dictate a 
specific means to manage vegetation. See, e.g., Memorandum of 
Understanding Among the Edison Electric Institute and the U.S. 
Department of Agriculture Forest Service and the U.S. Department of 
the Interior Bureau of Land Management, Fish and Wildlife Service, 
National Park Service and the U.S. Environmental Protection Agency 
(2006), with the stated purpose of establishing ``a framework for 
developing cooperative right-of-way integrated vegetation management 
(IVM) practices * * *''
    \124\ See, e.g., Piedmont Environmental Council v. FERC, 558 
F.3d 304 (4th Cir. 2009) (finding that no EIS was required for FERC 
rulemaking to implement FPA section 216 electric transmission line 
siting authority); Northcoast Environmental Center v. Glickman, 136 
F.3d 669 (9th Cir. 1998) (EA was not required for cedar management 
plan because, while providing management goals and strategies, the 
plan did not propose site-specific activities or call for specific 
actions directly impacting the environment); Northeast Utilities 
Service Co. v. FERC, 993 F.2d 937 at 958-9 (1st Cir. 1993) (holding 
that EIS was not required for utility merger based on fact that new 
generating facilities might wind up in different locations than 
would have been the case absent the merger because that fact was not 
of sufficient significance and ``its significance was not 
quantifiable'').
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    145. Further, we are not persuaded by the claims of APS and 
PacifiCorp. According to APS, because the Version 1 standard 
``compelled transmission owners to determine what should be appropriate 
for vegetation management,

[[Page 18836]]

the industry automatically referenced ANSI A-300 Best Management 
Practices for Tree Care Operations.'' \125\ While the Version 1 
standard references ANSI A-300, it does not require compliance with the 
document.\126\ Moreover, FAC-003-2 references the same document, again 
as a source for best industry practices in vegetation management.\127\ 
Thus, we are not persuaded by APS's claim that the change in references 
to ANSI A-300 will ``lead to weak links'' and possible ``regression'' 
in vegetation management practices, or that the revisions to the 
standard may result in a significant adverse effect on the human 
environment, let alone a substantial change to the regulation.
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    \125\ APS Comments at 5.
    \126\ Reliability Standard FAC-003-1, fn 1 provides in full: 
``ANSI A300, Tree Care Operations--Tree, Shrub, and Other Woody 
Plant Maintenance--Standard Practices, while not a requirement of 
this standard, is considered to be an industry best practice.''
    \127\ Reliability Standard FAC-003-2, Guidelines and Technical 
Basis, p. 20, provides, ``[a]n example of one approach commonly used 
by industry [to manage vegetation] is ANSI Standard A300.''
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    146. APS recommends that an EIS address implementation of ANSI A-
300 and best management practices on federal lands to ``provide 
transmission owners authority and allow them to define their program of 
work * * * and eliminate personal opinion when working at the local 
level of each federal agency.'' \128\ However, implementation of ANSI 
A-300 best practices is not a requirement of the Version 1 standard or 
FAC-003-2. Thus, we are not persuaded by APS that an EIS is required to 
study the implementation of ANSI A-300 best practices on federal lands.
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    \128\ APS Comments at 6.
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    147. For the reasons discussed above, we conclude that the 
Commission correctly asserted that approval of the revised Reliability 
Standard falls within the categorical exclusion set forth in section 
380.4(a)(2)(ii) of the Commission's rules and regulations for 
promulgation of rules that are ``clarifying, corrective or procedural, 
or that do not substantively change the effect of * * * regulations 
being amended.'' Accordingly, we will not require an EIS or EA on 
Reliability Standard FAC-003-2.

V. Regulatory Flexibility Act Certification

    148. The Regulatory Flexibility Act of 1980 (RFA) \129\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small entities. 
The RFA mandates consideration of regulatory alternatives that 
accomplish the stated objectives of a proposed rule and that minimize 
any significant economic impact on a substantial number of small 
entities. The Small Business Administration's (SBA) Office of Size 
Standards develops the numerical definition of a small business.\130\ 
The SBA has established a size standard for electric utilities, stating 
that a firm is small if, including its affiliates, it is primarily 
engaged in the transmission, generation and/or distribution of electric 
energy for sale and its total electric output for the preceding twelve 
months did not exceed four million megawatt hours.\131\
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    \129\ 5 U.S.C. 601-612.
    \130\ 13 CFR 121.101.
    \131\ 13 CFR 121.201, Sector 22, Utilities & n.1.
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    149. Reliability Standard FAC-003-2 applies to overhead 
transmission lines operated at 200 kV or higher, and, for the first 
time, to transmission lines operated at less than 200 kV if they are 
elements of an IROL or elements of a Major WECC Transfer Path. In 
addition, FAC-003-2 requires annual vegetation inspections for all 
applicable lines, which could result in an increase in annual 
inspections performed for a subset of transmission owners.
    150. Comparison of the NERC Compliance Registry with data submitted 
to the Energy Information Administration on Form EIA-861 indicates 
that, of the 330 transmission owners in the United States registered by 
NERC, 127 of these entities qualify as small businesses. The Commission 
estimates that the 127 transmission owners that qualify as small 
businesses will incur increased costs associated solely with a one-time 
review of the standard and modification to existing plans and 
procedures. As described in the information collection section of this 
Final Rule, the estimated cost for the increased data collection and 
retention is approximately $1,000 per entity.
    151. Further, some transmission owners that qualify as small 
entities will incur costs associated with an increase in frequency of 
inspections. As indicated above, the Version 1 standard requires 
periodic vegetation management inspections of transmission line rights-
of-way at an interval determined by each transmission owner. 
Requirement R6 of FAC-003-2 requires each transmission owners to 
inspect 100 percent of the transmission lines at least once per year. 
Based on a review of available information, including data provided in 
response to a 2004 vegetation management study performed by Commission 
staff,\132\ we estimate that approximately one third, i.e., 42, of the 
transmission owners that qualify as small entities would incur costs 
associated with more frequent inspection cycles. Assuming that (1) such 
small entities own approximately 50-200 miles of transmission lines, 
(2) approximately 15-20 miles of transmission line can be inspected per 
day and (3) cost of labor is approximately $47 per hour,\133\ the 
estimated increase in inspection cost for these 42 small entities is in 
the range of approximately $5,000 to $10,000 per entity. As discussed 
above, FAC-003-2 modifies the applicability of the Reliability Standard 
to include overhead transmission lines that are operated below 200 kV 
if they are either an element of an IROL or an element of a Major WECC 
Transfer Path. Based on a review of the Major WECC Transfer Paths and a 
sample of sub-200 kV IROLs in the Eastern Interconnect, the Commission 
believes that most, if not all, of the transmission lines subject to 
the expanded applicability of FAC-003-2 are owned by large entities. 
Thus, the increased cost of the new rule to small entities appears to 
be negligible with respect to the expanded applicability of the 
Reliability Standard.
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    \132\ See Utility Vegetation Management and Bulk Electric 
Reliability Report from the Federal Energy Regulatory Commission, p. 
8-10 (Sept. 7, 2004). Available at: https://www.ferc.gov/industries/electric/indus-act/reliability/veg-mgmt-rpt-final.pdf.
    \133\ The wage figure is taken from the Bureau of Labor and 
Statistics at https://bls.gov/oes/current/naics3_221000.htm.
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    152. Based on the above analysis, the Commission does not consider 
the cost of the modified Reliability Standard to be a significant 
economic impact for small entities because it should not represent a 
significant percentage of an affected small entity's operating budget.
    153. Based on this understanding, the Commission certifies that the 
Reliability Standard will not have a significant economic impact on a 
substantial number of small entities. Accordingly, no regulatory 
flexibility analysis is required.

VI. Document Availability

    154. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (https://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5:00 
p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington DC 
20426.

[[Page 18837]]

    155. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    156. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

VII. Effective Date and Congressional Notification

    157. These regulations are effective May 28, 2013. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    Note:  The Appendix will not appear in the Code of Federal 
Regulations.

Appendix

Commenters

American Electric Power Service Corporation (AEP)
Arizona Public Service Company (APS)
Bonneville Power Administration (BPA)
The City of Santa Clara, California, d/b/a Silicon Valley Power 
(Santa Clara)
Duke Energy Corporation (Duke)
Electric Power Research Institute (EPRI)
FirstEnergy Service Company (FirstEnergy)
Idaho Power Company (Idaho Power)
International Transmission Company d/b/a/ITCTransmission, Michigan 
Electric Transmission Company, LLC, ITC Midwest LLC and ITC Great 
Plains LLC (ITC Companies)
Kansas City Power & Light Company and KCP&L Greater Missouri 
Operations Company, subsidiaries of Great Plains Energy, Inc. (KCPL)
Manitoba Hydro
The New England States Committee on Electricity (NESCOE)
North American Electric Reliability Corporation (NERC)
Pacific Gas and Electric Company (PG&E)
PacifiCorp
The Pennsylvania Public Utility Commission (PA PUC)
Southern Company Services, Inc., on behalf of Alabama Power Company, 
Georgia Power Company, Gulf Power Company, and Mississippi Power 
Company (Southern Companies)
Trade Associations (jointly, Edison Electric Institute, American 
Public Power Association, Large Public Power Council, National Rural 
Electric Cooperative Association, and Transmission Access Policy 
Study Group)
Vermont Electric Power Company, Inc. (VELCO)
Washington State Department of Natural Resources (Washington DNR)

[FR Doc. 2013-07113 Filed 3-27-13; 8:45 am]
BILLING CODE 6717-01-P