142 FERC ¶ 61,208

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 40

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

Revisions to Reliability Standard for

Transmission Vegetation Management

(Issued March 21, 2013)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule.

SUMMARY: Under section 215 of the Federal Power Act (FPA), the Federal Energy 

Regulatory Commission (Commission) approves Reliability Standard FAC-003-2

(Transmission Vegetation Management), submitted to the Commission for approval by 

the North American Electric Reliability Corporation (NERC), the Commission-certified 

Electric Reliability Organization. Reliability Standard FAC-003-2 expands the 

applicability of the standard to include overhead transmission lines that are operated 

below 200 kV, if they are either an element of an Interconnection Reliability Operating 

Limit or an element of a Major WECC Transfer Path. Reliability Standard FAC-003-2

incorporates a new minimum annual inspection requirement, and incorporates new 

minimum vegetation clearance distances into the text of the standard.

The Commission also approves the related definitions, violation severity levels, 

implementation plan, and effective dates proposed by NERC. The Commission approves 
Docket No. RM12-4-000 ii

the related violation risk factors, except that it directs a revision to the violation risk 

factor corresponding to one requirement.

EFFECTIVE DATE: This rule will become effective [insert date 60 days after 

publication in the FEDERAL REGISTER].

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: 
142 FERC ¶ 61,208

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Revisions to Reliability Standard for 

 Transmission Vegetation Management 

Docket No. RM12-4-000

ORDER NO. 777

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

 

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 

 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).
Docket No. RM12-4-000 - 2 -

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.

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 

 3 NERC defines “IROL” as “[a] System Operating Limit that, if violated, could 

lead to instability, uncontrolled separation, or Cascading outages that adversely impact 

the reliability of the Bulk Electric System.” NERC defines “System Operating Limit” as 

“[t]he value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the most 

limiting of the prescribed operating criteria for a specified system configuration to ensure 

operation within acceptable reliability criteria.” See NERC Glossary of Terms Used in 

Reliability Standards (NERC Glossary) at 26, 48. The Western Electricity Coordinating 

Council (WECC) maintains a listing of Major WECC Transfer Paths, available at

http://www.wecc.biz/Standards/Development/WECC-0091/Shared Documents/WECC0091 Table Major Paths 4-28-08.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.
Docket No. RM12-4-000 - 3 -

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

 

 5 See U.S.-Canada Power System Outage Task Force, Final Report on the August 

14, 2003 Blackout in the United States and Canada: Causes and Recommendations at 18, 

57-64 (April 2004) (2003 Blackout Report). 

6 See written remarks by Gerry Cauley, NERC’s Chief Executive Officer, for the 

November 29, 2011 Reliability Technical Conference at 1, 4 and 5 (Docket No. AD12-1-

000).

7 See, e.g., NERC’s Third Quarter 2012 Vegetation-Related Transmission Outage 

Report at 6-7, available at http://www.nerc.com/files/Item%202%20--

%20Third%20Quarter%20Vegetation%20Report.pdf. 

8 Revisions to Reliability Standard for Transmission Vegetation Management, 

Notice of Proposed Rulemaking, 141 FERC ¶ 61,046 (Oct. 18, 2012).
Docket No. RM12-4-000 - 4 -

4. We also approve the three new or revised definitions associated with the proposed 

Reliability Standard for inclusion in the NERC Glossary. Specifically ̧ we approve the 

changes in the definition of “Right-of-Way” and “Vegetation Inspection,” as well as the 

addition of the term “Minimum Vegetation Clearance Distance (MVCD)” as defined in 

NERC’s petition. We also approve NERC’s implementation plan for FAC-003-2. 

5. NERC has not adequately supported the proposed assignment of a “medium”

Violation Risk Factor to Requirement R2, which pertains to preventing vegetation 

encroachments into the MVCD of transmission lines operated at 200 kV and above, but 

which are not part of an IROL or a Major WECC Transfer Path. As discussed later, 

system events have originated from non-IROL facilities. Accordingly, we adopt the 

NOPR proposal and direct NERC to submit a modification, within 60 days of the 

effective date of the Final Rule, assigning a “high” Violation Risk Factor for 

Requirement R2. 

6. As discussed below, we also direct NERC to develop a means to assure that 

IROLs are communicated to transmission owners.

I. Background

A. Section 215 of the FPA

7. Section 215 of the FPA requires the Commission-certified ERO to develop 

mandatory and enforceable Reliability Standards, subject to Commission review and 

approval. Once approved, the Reliability Standards may be enforced by the ERO subject 
Docket No. RM12-4-000 - 5 -

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 ERO10 and, subsequently, certified NERC as the ERO.11 

B. Reliability Standard FAC-003-2 and NERC Explanation of 

Provisions12

8. Reliability Standard FAC-003-2 includes seven requirements.13

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, 

 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).

12 Reliability Standard FAC-003-2 is not attached to the Final Rule. The complete 

text of Reliability Standard FAC-003-2 is available on the Commission’s eLibrary 

document retrieval system in Docket No. RM12-4-000 and is posted on the ERO’s web 

site, available at: http://www.nerc.com. 

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.

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”).
Docket No. RM12-4-000 - 6 -

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

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

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.” 

 15 NERC Petition at 6.

16 Id. at 22. 

17 See proposed Reliability Standard FAC-003-2, n.2. 

18 NERC Petition at 23.
Docket No. RM12-4-000 - 7 -

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

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 

 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.
Docket No. RM12-4-000 - 8 -

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

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.

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 

 21 See id. at 24-25. 

22 Id. at 17-18.
Docket No. RM12-4-000 - 9 -

entities plan to prevent encroachments into the MVCD, but simply that they implement 

whatever is included in the plan.”23

C. Procedural Activities 

1. Pacific Northwest National Laboratory Report

16. NERC explained in its petition that the Standard Drafting Team applied the 

“Gallet equation” to derive the MVCDs set forth in FAC-003-2. NERC described the 

Gallet equation as a “well-known method of computing the required strike distance for 

proper insulation coordination.”24 The Commission’s Office of Electric Reliability 

retained the Pacific Northwest National Laboratory (PNNL) to undertake an “analysis of 

the mathematics and documentation of the technical justification behind the application 

of the Gallet equation and the assumptions used in the technical reference paper [Exh. A 

of NERC’s petition].”25 

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

 23 Id. at 28. For additional background pertaining to NERC’s petition, see NOPR, 

141 FERC ¶ 61,046 at PP 32-36. 

24 NERC Petition, Ex. I (Technical Reference Document) at 39. 

25 See April 23, 2012 Notice Inviting Comments on Report. 

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. 
Docket No. RM12-4-000 - 10 -

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 
Docket No. RM12-4-000 - 11 -

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. 

 27 NOPR, 141 FERC ¶ 61,046 at PP 57-61.
Docket No. RM12-4-000 - 12 -

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 defensein-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.

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, 

 28 NERC Comments at 3.

29 Duke, KCPL, PacifiCorp, PG&E and Southern Companies support the 

comments submitted by Trade Associations.
Docket No. RM12-4-000 - 13 -

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.

25. NESCOE generally supports FAC-003-2 as representing appropriate 

enhancements to the Version 1 standard in a number of critical areas. While noting that 

the Reliability Standard is not designed to address severe weather events and natural 

disasters such as the October 2011 Northeast snowstorm, NESCOE states that more 

clearly defined clearance requirements and stricter vegetation management practices 

should have the attendant benefit of reducing the risk to Bulk-Power System reliability 

during such events. However, NESCOE believes that NERC should be required to 

demonstrate that the proposal is supported by a cost analysis, i.e., that the incremental 

reliability gains outweigh the added costs. Therefore, NESCOE recommends that the 

Commission grant “interim approval” to FAC-003-2, with final approval conditioned on 

NERC supporting the proposal with a cost-benefit analysis.

26. APS comments that the Version 1 standard, FAC-003-1, has proven effective and 

the Commission should consider “maintaining” that standard. APS notes that the number 

of outages caused by vegetation grow-in has steadily declined since implementation of 

the Version 1 standard, and APS attributes this decline largely to the “Clearance 1” 

requirement that transmission owners develop and document their plan to manage the 

vegetation on rights-of-way at the time of work. APS expresses concern that a different 

approach may be less effective. Alternatively, if FAC-003-2 is approved, APS suggests 

integrating a Clearance 1 requirement in that standard.
Docket No. RM12-4-000 - 14 -

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 above 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. 

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 

 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.
Docket No. RM12-4-000 - 15 -

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

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 

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 

 31 NERC Petition at 6. 

32 See Reliability Standard FAC-003-2 at p 20-22.

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. 
Docket No. RM12-4-000 - 16 -

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. 

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

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. 

 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).

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.
Docket No. RM12-4-000 - 17 -

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

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 

 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.

39 NERC Comments at 5.
Docket No. RM12-4-000 - 18 -

obtain IROL information. According to NERC, this provision requires the planning 

authority (a term synonymous with planning coordinator) to “provide its SOLs and 

IROLs to entities with a reliability-related need, such as a Transmission Owner, who 

request such information.”40 NERC further offers that “[i]f the Commission does not 

agree that Transmission Owners can obtain information directly from Planning 

Coordinators under Requirement R5 of FAC-014,” transmission owners have other 

means such as Requirement R8 of Reliability Standard TPL-001-2 as well as existing 

agreements between transmission owners and transmission operators.41 Regarding 

changes in IROL status, NERC comments that the burden is on the transmission owner to 

procure this information as part of its responsibility to manage vegetation to prevent 

encroachment and as the entity responsible for implementing FAC-003-2.

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. 

 40 Id. See also Technical Reference Document at p. 12.

41 NERC Comments at 5-6.
Docket No. RM12-4-000 - 19 -

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 FAC014 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 
Docket No. RM12-4-000 - 20 -

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 reliabilityrelated 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 

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 

 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. 
Docket No. RM12-4-000 - 21 -

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.
Docket No. RM12-4-000 - 22 -

43. With regard to the concern in the NOPR on the changing status of IROLs, we 

accept the explanation of Trade Associations that a vegetation management program 

should be based on the near term planning horizon of one to five years, in which case 

applicable transmission owners will not be responsible to document compliance with 

day-to-day operating changes to IROLs. Likewise, we agree with Idaho Power that 

transmission owners should be responsible for vegetation management on lines that can 

become IROLs during “studied credible contingencies.” Based on the methodology set 

forth in FAC-014, sub-200 kV transmission lines that are identified as elements of an 

IROL or Major WECC Transfer Path are subject to FAC-003-2. For example, some 

entities identify seasonal IROLs and we expect sub-200 kV elements of seasonal IROLs 

to be subject to FAC-003-2.44 In contrast, as suggested by Idaho Power, if, for example,

a multiple contingency results in the operation of the system in an unknown state for a 

limited period of time, a transmission owner is not responsible for compliance with FAC003-2 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 FAC003-2. 

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 

 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. 
Docket No. RM12-4-000 - 23 -

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 sub200 kV lines that are either an element of an IROL or a major WECC Transfer Path.

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 

 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.
Docket No. RM12-4-000 - 24 -

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. 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 

 47 NESCOE Comments at 6.

48 NOPR, 141 FERC ¶ 61,046 at P 65.
Docket No. RM12-4-000 - 25 -

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. 

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 

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 

 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).
Docket No. RM12-4-000 - 26 -

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 sparkover 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 
Docket No. RM12-4-000 - 27 -

conducted to obtain the empirical data the Commission seeks...”52 According to NERC, 

this alternative approach would allow NERC flexibility to discuss study scope and 

funding with the Commission, allow for the development of partnerships in conducting 

the study, and allow collaboration on the study and any necessary changes to the 

Reliability Standard. NERC asks that, if directed to conduct empirical research, the Final 

Rule address (1) the need for the empirical data and scope of the study, (2) time frame for 

the study – and allow NERC to submit a proposed schedule for completion, and (3) 

funding of the study. 

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 

 52 NERC Comments at 10.
Docket No. RM12-4-000 - 28 -

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 
Docket No. RM12-4-000 - 29 -

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 
Docket No. RM12-4-000 - 30 -

factor to be applied in calculating minimum clearance distances using the Gallet 

equation.

53 

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. 

 53 We will not specify that NERC retain EPRI or any other particular entity to 

conduct the required testing.

54 NOPR, 141 FERC ¶ 61,046 at P 71.

55 See NOPR, 141 FERC ¶ 61,046 at P 47.
Docket No. RM12-4-000 - 31 -

61. NERC asks that we accept its commitment to move forward with the study. 

However, our determination that such a study is needed warrants imposing a directive for 

its completion. Thus, we direct NERC, within 45 days of the effective date of this Final 

Rule, to submit an informational filing that includes, inter alia: (1) a schedule for testing, 

(2) scope of work, (3) funding solutions, and (4) deadline for submitting a final report to 

the Commission on the test results (and interim reports if a multi-year study is 

conducted). This approach should give NERC the flexibility to consult with the 

Commission or its staff as well as industry members to determine the technical 

specifications for the required study, funding sources and timing. However, given the 

importance of the testing set forth in our determination, the filing and schedule must 

include a reasonable date for the submission of a final report on the results of the 

empirical study. 

62. With regard to the comments of PacifiCorp and APS on compliance with the 

MVCD values under all rated conditions, we disagree that FAC-003-2 should be revised 

to allow transmission owners to remedy MVCD encroachments prior to an outage 

without a violation. NERC indicates that, under FAC-003-2, transmission operators will 

manage vegetation to distances beyond the MVCD to ensure no encroachment into the 

MVCD.56 Thus, in response to PacifiCorp and APS, a vegetation management strategy

required by Requirement R3 of FAC-003-2 must provide enough clearance to ensure that 

the MVCD will not be encroached under any conditions. 

 56 See NOPR, 141 FERC ¶ 61,046 at PP 67-70 (discussing NERC Petition and 

maintenance of vegetation beyond MVCD values).
Docket No. RM12-4-000 - 32 -

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 

 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. 
Docket No. RM12-4-000 - 33 -

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 

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

 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). 

63 NERC Petition, Ex. A at 20-21. 
Docket No. RM12-4-000 - 34 -

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. 

65. Finally, as NERC explained in its Technical Reference Document, transmission 

owners will have to clear vegetation to levels “well away from” the minimum spark-over 

zone:

As the conductor moves through various positions [due to 

thermal loading and physical loading], a spark-over zone 

surrounding the conductor moves with it. . . . At the time of 

making a field observation, however, it is very difficult to 

precisely know where the conductor is in relation to its wide 

range of all possible positions. Therefore, Transmission 

 64 See id. and Requirement R3 of FAC-003-2; see also NERC Petition, Ex. I 

(Technical Reference Document) at 20-29.
Docket No. RM12-4-000 - 35 -

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

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 

 65 NERC Petition, Ex. I (Technical Reference Document) at 21-24. 
Docket No. RM12-4-000 - 36 -

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.

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

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 

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

67 NOPR, 141 FERC ¶ 61,046 at P 81.

68 NERC Comments at 13.
Docket No. RM12-4-000 - 37 -

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 

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. 

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 

 69 NERC Comments at 13.

70 Trade Association Comments at 5.
Docket No. RM12-4-000 - 38 -

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

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

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 

 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). 

72 Id. (emphasis added). 
Docket No. RM12-4-000 - 39 -

definition of “medium” Violation Risk Factor provides in part that “violation of a 

medium risk requirement is unlikely to lead to bulk electric system instability, separation, 

or cascading failures.” In the NOPR, the Commission questioned NERC’s rationale, 

stating that “NERC does not explain why outages on these relatively high voltage lines 

(200 kV or higher) would not likely lead to cascading, separation, or instability...”73 

Further, the Commission pointed out that transmission lines not designated as an IROL 

element (or the equivalent) have been instrumental in causing major blackouts, including 

the August 2003 Northeast blackout and an August 10, 1996 blackout in the Western 

Interconnection.74 Rather than responding to the Commission’s request for an 

explanation of why outages on high voltage, non-IROL lines are unlikely to lead to 

instability, separation or cascading, NERC and others simply reiterate their previous 

rationale. Thus, we conclude that NERC and other commenters have not adequately 

supported a “medium” Violation Risk Factor designation for Requirement R2.

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 

 73 NOPR, 141 FERC ¶ 61,046 at P 77.

74 Id. at PP 78-79.
Docket No. RM12-4-000 - 40 -

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

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 

 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 See Reliability Standard FAC-003-2, n.2. 
Docket No. RM12-4-000 - 41 -

conditions outside their control lead to an encroachment that otherwise would not have 

occurred.”78 

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 contractorcaused 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. 

 78 NERC Petition at 23. 
Docket No. RM12-4-000 - 42 -

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 caseby-case analysis, including the scenarios described by BPA. 
Docket No. RM12-4-000 - 43 -

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, 
Docket No. RM12-4-000 - 44 -

animal activities, or other environmental conditions outside their control lead to an 

encroachment that otherwise would not have occurred.”79 

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. 

 79 NERC Petition at 23. 
Docket No. RM12-4-000 - 45 -

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 

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 

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

81 NERC Petition at 23-24.
Docket No. RM12-4-000 - 46 -

with NERC, they can develop a Standards Authorization Request (SAR) and submit it to 

NERC for consideration.

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

Comments

89. NERC comments that it does not object to consolidating the reference material and 

posting it on the NERC website 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. 

 82 NOPR, 141 FERC ¶ 61,046 at P 91.
Docket No. RM12-4-000 - 47 -

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 website 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

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 

 83 NOPR, 141 FERC ¶ 61,046 at P 92.
Docket No. RM12-4-000 - 48 -

NERC, the expectation in Requirement R4 is that once the transmission owner has 

confirmed the existence of a vegetation condition that is likely to cause an imminent 

fault, the transmission owner must immediately notify the control center. NERC explains 

that the standard drafting team did not include a “quantitative” time element for 

notification in Requirement R4 due to the difficulty in determining one time period that 

applies to all situations. 

93. Trade Associations, Duke and Southern Companies comment that the inquiry into 

whether a transmission owner’s notification occurred “without any intentional time 

delay” is a fact specific determination. Southern Companies adds that the drafting team 

considered a specific time window for notifying the control center but adopted the current 

language because it (i) avoids an arbitrarily narrow time-frame and (ii) provides a clear 

metric. PacifiCorp comments that, because the severity of an event will “vary across 

facts and circumstances,” it recommends the “development of a load factor above which 

the failure to promptly report a vegetation condition ... would warrant a high severity 

level and below which would warrant a lesser severity level.”84 Idaho Power comments 

that the cause of the delay must be assessed and degrees of failure could be addressed in 

Violation Severity Levels or, if delays result from administrative process issues, 

addressed in the “find, fix and track” process.

 84 PacifiCorp Comments at 5.
Docket No. RM12-4-000 - 49 -

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 
Docket No. RM12-4-000 - 50 -

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.

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 

 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.”)

87 NERC Comments at 16 (citing NERC Rules of Procedure, App. 4C 

(Compliance Monitoring and Enforcement Program), at Att. 1).
Docket No. RM12-4-000 - 51 -

include Regional Entity audits, spot checks and investigations of vegetation-caused 

outages.

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 
Docket No. RM12-4-000 - 52 -

more compliance resources to oversight of an entity that fails to comply with a reporting 

requirement.88 

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 selfreport 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, 

 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).
Docket No. RM12-4-000 - 53 -

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

E. Definition of Right-of-Way

103. NERC modified the definition of “Right-of-Way” as follows: 

The corridor of land under a transmission line(s) needed to operate the 

line(s). The width of the corridor is established by engineering or 

construction standards as documented in either construction documents, 

pre-2007 vegetation maintenance records, or by the blowout standard in 

effect when the line was built. The ROW width in no case exceeds the 

Transmission Owner’s legal rights but may be less based on the 

aforementioned criteria. 

104. While the Commission in the NOPR proposed to approve the right-of-way

definition, it also sought comment on certain aspects of the definition. Below, we discuss 

the following matters related to the right-of-way definition: (1) guidance for defining an 

appropriate right-of-way; (2) NERC’s approach to fall-ins by “danger trees”; and 

(3) vegetation management strategies.

 89 18 CFR § 39.2 (2012).
Docket No. RM12-4-000 - 54 -

1. Guidance for Defining an Appropriate Right-of-Way

NOPR 

105. In the NOPR, the Commission observed that, because fall-ins, blow-ins and growins 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-ofway definition includes guidance as to how the transmission owner may define its rightof-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

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 

 90 NOPR, 141 FERC ¶ 61,046 at P 97.

91 NOPR, 141 FERC ¶ 61,046 at P 102.

92 NERC Comments at 16-17 (emphasis in original) (citing Reliability Standard 

FAC-003-2, Requirements R1(4) and R2(4)).
Docket No. RM12-4-000 - 55 -

incentive to set right-of-way widths properly to ensure that the land needed to operate a 

transmission line is included. 

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. 

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 

 93 NERC Comments at 20. See also BPA Comments at 5.
Docket No. RM12-4-000 - 56 -

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 rightof-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 
Docket No. RM12-4-000 - 57 -

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.

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-bycase 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, 

 94 Reliability Standard FAC-003-2, Requirement R1, subsection (4).
Docket No. RM12-4-000 - 58 -

questioned NERC’s approach to a fall-in by “danger timber” in that same range. NERC 

explained that, “if the TO is regularly identifying its danger trees and has a program for 

managing the risk of fall-in there would be no violation.”95 The Commission expressed 

concern that this statement “could be read to mean that, as long as the transmission owner 

identifies danger trees and has a program to manage the risk of those trees, an 

encroachment into the MVCD from a location within the transmission owner’s control 

would not be a violation.”96 The Commission disagreed with such an approach because 

the mere existence of a program to identify danger trees and a program to manage risk 

should not shield a transmission owner from enforcement.

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. 

 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.
Docket No. RM12-4-000 - 59 -

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 

 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.” 
Docket No. RM12-4-000 - 60 -

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 caseby-case basis.

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 
Docket No. RM12-4-000 - 61 -

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 

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 

 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.
Docket No. RM12-4-000 - 62 -

must have a well-managed, danger tree management program as carried out through 

Requirements R6 and R7.

100

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 FAC003-2 provide the basis for determining a transmission owner’s compliance with the 

corresponding Requirements R6 and R7. We agree with Trade Associations and Duke 

that a potential violation of Requirements R6 and R7 should not be based on “post hoc” 

analyses of whether a transmission owner correctly identified a dead or diseased tree. A 

fall-in from outside of the defined right-of-way may give reason to review a transmission 

owner’s compliance with the annual inspection and work plan requirements. In the 

context of fall-ins from outside the defined right-of-way, enforcement decisions should 

be based on a review of the quality of the transmission owner’s program and its execution 

of that program.

3. Vegetation Management Strategies

NOPR

121. In the NOPR, the Commission noted that FAC-003-2 does not require clearcutting 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 

 100 NERC Comments at 19-20. 
Docket No. RM12-4-000 - 63 -

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.

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 

 101 NOPR, 141 FERC ¶ 61,046 at P 100 (citing NERC Petition, Ex. I (Technical 

Reference Document) at 24-29).

102 Trade Association Comments at 13. See also ITC Comments at 6-7.
Docket No. RM12-4-000 - 64 -

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 websites 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. 

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-ofway, 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 rightof-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 
Docket No. RM12-4-000 - 65 -

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.

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

 103 APS Comments at 8.

104 NERC Petition at 17, 20, 35.
Docket No. RM12-4-000 - 66 -

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.

127. With regard to comments on the implementation of vegetation management 

strategies, we agree that ANSI-A 300 is a commonly recognized source for best 

vegetation management practices. We disagree with PacifiCorp, however, that we are 

seeking to apply a “double standard” by supporting a zero tolerance approach to 

compliance with FAC-003 while also opposing tree removal. We understand that, as 

explained by Trade Associations and other commenters, best practices call for the 

removal of tall-growing vegetation from the right-of-way and replacement with a 

sustainable plant community. In many circumstances, this is a reasonable approach. 

However, we also believe that a transmission owner should not monolithically equate 

vegetation management with tree removal. Circumstances may provide greater latitude, 

for example, when addressing the concerns of an individual landowner and where the 

species of vegetation are not genetically disposed to encroach into the MVCD. Certainly, 

as recognized by APS, a transmission owner decision’s to remove vegetation in such 

circumstances should not be ascribed to the Commission.

128. Ultimately, transmission owners should work with private land owners to 

determine an appropriate approach that assures reliability and respects private land owner 

concerns. As noted by commenters, this approach requires clear communications 

between transmission owners and private landowners; and meaningful outreach should 
Docket No. RM12-4-000 - 67 -

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. 

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 

 105 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 732.
Docket No. RM12-4-000 - 68 -

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. 

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 recordkeeping and reporting. In addition, by allowing greater flexibility compared to the 

 106 5 CFR 1320.11.
Docket No. RM12-4-000 - 69 -

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 ongoing, 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 
Docket No. RM12-4-000 - 70 -

increase the inspection cycles (and the associated documentation to demonstrate 

compliance) for about one third of transmission owners (110 transmission owners).

FAC-003-2 

(Transmission 

Vegetation 

Management) 

Number of 

Transmission Owner 

Respondents

(1)

Number of 

Responses 

per 

Respondent

(2)

Average 

Burden 

Hours Per 

Response

(3)

Total 

Annual 

Burden 

Hours

(1)x(2)x(3)

One time review and 

modifications to 

existing 

documentation, plans 

and procedures

330 1 16 5,280 

(one-time)

Quarterly Reporting 115107 4 0.5 230

Annual Vegetation 

Inspections 

Documentation 110 1 2 220

Total 5,730

Total Annual Hours for Collection: (Compliance/Documentation) = 5,730 hours. 

Quarterly Reporting Cost for Transmission Owners: = 230 hours @ $70/hour108= 

$16,100. 

Annual Vegetation Inspections Documentation: = 220 hours @ $28/hour109 = $6,160.

 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.

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 website at 

http://bls.gov/oes/current/naics3_221000.htm. 

109 Wage figure is based on a Commission staff study of record retention burden.
Docket No. RM12-4-000 - 71 -

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/hour110 = $274,560.

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. 

 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 website at 

http://bls.gov/oes/current/naics3_221000.htm.
Docket No. RM12-4-000 - 72 -

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, 

e-mail: 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 e-mail 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 

 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).
Docket No. RM12-4-000 - 73 -

clarifying, corrective, or procedural, or that do not substantially change the effect of the 

regulations being amended.112 

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

 112 See NOPR, 141 FERC ¶ 61,046 at P 116 (citing 18 CFR 380.4(a)(2)(ii)). 

113 Washington DNR Comments at 3.
Docket No. RM12-4-000 - 74 -

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 

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 A300 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.
Docket No. RM12-4-000 - 75 -

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. 

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

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-

 116 Order No. 486, FERC Stats. & Regs. ¶ 30,783.

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.

118 NERC’s Version 1 ROW definition provides: 
Docket No. RM12-4-000 - 76 -

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 rightof-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.

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 

 

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.
Docket No. RM12-4-000 - 77 -

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 

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 

 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.

123 In certain circumstances, transmission owners will negotiate the vegetation 

management activities they undertake to comply, also showing that the new standard 
Docket No. RM12-4-000 - 78 -

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 

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, the industry automatically referenced 

 

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 sitespecific 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”).
Docket No. RM12-4-000 - 79 -

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. 

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.

 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.”

128 APS Comments at 6.
Docket No. RM12-4-000 - 80 -

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 

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 

 129 5 U.S.C. 601-612.

130 13 CFR 121.101.

131 13 CFR 121.201, Sector 22, Utilities & n.1. 
Docket No. RM12-4-000 - 81 -

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 
Docket No. RM12-4-000 - 82 -

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.

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. 

 132 See Utility Vegetation Management and Bulk Electric Reliability Report from 

the Federal Energy Regulatory Commission, p. 8-10 (Sept. 7, 2004). Available at: 

http://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 

http://bls.gov/oes/current/naics3_221000.htm.
Docket No. RM12-4-000 - 83 -

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 

(http://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.

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 website 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. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.
Docket No. RM12-4-000 - 84 -

VII. Effective Date and Congressional Notification

157. These regulations are effective [insert date 60 days from the date the rule is 

published in the Federal Register]. 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.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM12-4-000 - 85 -

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)
Docket No. RM12-4-000 - 86 -

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)