RM07-3-000 NOPR (Federal Register)

Federal Register / Vol. 72, No. 160 / Monday, August 20, 2007 / Proposed Rules
January 22, 2003, revised May 19, 2006; and
DG Flugzeugbau GmbH Drawing 5M211,
Spindle drive Stross BSA 10 assembly with
strengthened fork 8M233‘‘f’’, dated January
23, 2006, for related information.
Issued in Kansas City, Missouri, on August
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Terry L. Chasteen,
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[FR Doc. E7–16302 Filed 8–17–07; 8:45 am]
BILLING CODE 4910–13–P

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM07–3–000]

Facilities Design, Connections and
Maintenance Reliability Standards
August 13, 2007.

Federal Energy Regulatory
Commission, DOE.
ACTION: Notice of proposed rulemaking.

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AGENCY:

SUMMARY: Pursuant to section 215 of the
Federal Power Act (FPA), the
Commission is proposing to approve
three Reliability Standards developed
by the North American Electric
Reliability Corporation (NERC), which
the Commission has certified as the
Electric Reliability Organization
responsible for developing and
enforcing mandatory Reliability
Standards. The three new Reliability
Standards, designated by NERC as FAC–
010–1, FAC–011–1 and FAC–014–1, set
requirements for the development of
system operating limits of the BulkPower System for use in the planning
and operation horizons.
DATES: Comments are due September
19, 2007.
ADDRESSES: Comments and reply
comments may be filed electronically
via the eFiling link on the Commission’s
Web site at http://www.ferc.gov.
Documents created electronically using
word processing software should be
filed in the native application or printto-PDF format and not in a scanned
format. This will enhance document
retrieval for both the Commission and
the public. The Commission accepts
most standard word processing formats
and commenters may attach additional
files with supporting information in
certain other file formats. Attachments
that exist only in paper form may be
scanned. Commenters filing
electronically should not make a paper
filing. Service of rulemaking comments

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is not required. Commenters that are not
able to file electronically must send an
original and 14 copies of their
comments to: Federal Energy Regulatory
Commission, Office of the Secretary,
888 First Street, NE., Washington, DC
20426.
FOR FURTHER INFORMATION CONTACT:
Christy Walsh (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–6523.
Robert Snow (Technical Information),
Office of Energy Markets and
Reliability, Division of Reliability,
Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
6716.
Kumar Agarwal (Technical
Information), Office of Energy Markets
and Reliability, Division of
Reliability, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
8923.
SUPPLEMENTARY INFORMATION:
1. Pursuant to section 215 of the
Federal Power Act (FPA), the
Commission is proposing to approve
three Reliability Standards developed
by the North American Electric
Reliability Corporation (NERC), which
the Commission has certified as the
Electric Reliability Organization
responsible for developing and
enforcing mandatory Reliability
Standards. The three new Reliability
Standards, designated by NERC as FAC–
010–1, FAC–011–1 and FAC–014–1, set
requirements for the development of
system operating limits of the BulkPower System for use in the planning
and operation horizons.1
I. Background

1 The Commission is not proposing any new or
modified text to its regulations. Rather, as set forth
in 18 CFR part 40, a proposed Reliability Standard
will not become effective until approved by the
Commission, and the ERO must post on its Web site
each effective Reliability Standard.
2 Energy Policy Act of 2005, Pub. L. 109–58, Title
XII, Subtitle A, 119 Stat. 594, 941 (2005), to be
codified at 16 U.S.C. 824o.

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Once approved, the Reliability
Standards may be enforced by the ERO,
subject to Commission oversight or the
Commission can independently enforce
Reliability Standards.3
3. On February 3, 2006, the
Commission issued Order No. 672,
implementing section 215 of the FPA.4
Pursuant to Order No. 672, the
Commission certified one organization,
NERC, as the ERO.5 The ERO is required
to develop Reliability Standards, which
are subject to Commission review and
approval. The Reliability Standards will
apply to users, owners and operators of
the Bulk-Power System, as set forth in
each Reliability Standard.
B. NERC’s Proposed New Reliability
Standards
4. On November 15, 2006, NERC filed
20 revised Reliability Standards and
three new Reliability Standards for
Commission approval. The Commission
addressed the 20 revised Reliability
Standards in Order No. 693.6 The three
new Reliability Standards were
designated by NERC as follows:
FAC–010–1 (System Operating Limits
Methodology for the Planning Horizon);
FAC–011–1 (System Operating Limits
Methodology for the Operations
Horizon); and
FAC–014–1 (Establish and
Communicate System Operating Limits).
These three Reliability Standards
were assigned to a new rulemaking
proceeding, Docket No. RM07–3–000,
and are the subject of the current Notice
of Proposed Rulemaking (NOPR).7
5. In addition, NERC proposes the
addition or revision of the following
terms in the NERC Glossary of Terms
Used in Reliability Standards (NERC
glossary): ‘‘cascading outages,’’ ‘‘delayed
fault clearing,’’ ‘‘Interconnection
3 16

A. EPAct 2005 and Mandatory
Reliability Standards
2. On August 8, 2005, the Electricity
Modernization Act of 2005, which is
Title XII, Subtitle A, of the Energy
Policy Act of 2005 (EPAct 2005), was
enacted into law.2 EPAct 2005 adds a
new section 215 to the FPA, which
requires a Commission-certified ERO to
develop mandatory and enforceable
Reliability Standards, which are subject
to Commission review and approval.

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U.S.C. 824o(e)(3).
Concerning Certification of the Electric
Reliability Organization; Procedures for the
Establishment, Approval and Enforcement of
Electric Reliability Standards, Order No. 672, 71 FR
8662 (February 17, 2006), FERC Stats. & Regs.
¶ 31,204 (2006), order on reh’g, Order No. 672–A,
71 FR 19814 (April 18, 2006), FERC Stats. & Regs.
¶ 31,212 (2006).
5 North American Electric Reliability Corp., 116
FERC ¶ 61,062 (ERO Certification Order), order on
reh’g & compliance, 117 FERC ¶ 61,126 (ERO
Rehearing Order) (2006), order on compliance, 118
FERC ¶ 61,030 (2007) (January 2007 Compliance
Order).
6 On March 16, 2007, the Commission approved
83 of the 107 standards initially filed by NERC. See
Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, 72 FR, 16,416 (April 4,
2007), FERC Statutes and Regulations ¶ 31,242
(2007), order on reh’g Order No. 693–A, 120 FERC
¶ 61,053 (2007).
7 The three Reliability Standards are not attached
to this NOPR but are available on the Commission’s
eLibrary document retrieval system in Docket No.
RM07–3–000 and on NERC’s Web site, http://
www.nerc.com/~filez/nerc_filings_ferc.html.
4 Rules

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Federal Register / Vol. 72, No. 160 / Monday, August 20, 2007 / Proposed Rules

Reliability Operating Limit (IROL),’’ and
‘‘Interconnection Reliability Operating
Limit Tv (IROL Tv).’’ 8
6. NERC states that the three new
Reliability Standards ensure that system
operating limits and interconnection
reliability operating limits are
developed using consistent methods
and that those methods contain certain
essential elements.9 NERC requests an
effective date of July 1, 2007 for
Reliability Standards FAC–010–1,
October 1, 2007 for FAC–011–1, and
January 1, 2008 for FAC–014–1. NERC
explains that it has proposed a phased
schedule for implementing these
Reliability Standards so that each
responsible entity has sufficient time to
develop the methodology for
determining stability limits associated
with a list of multiple contingencies, to
update the system operating limits as
needed to comply with the new
requirements, to communicate the limits
to others, and to prepare the
documentation necessary to
demonstrate compliance.
7. NERC states that the original
balloting for FAC–010–1 and FAC–011–
1 took place in March 2006, but failed
to reach a quorum.10 These Reliability
Standards were revised and posted for
comment during June and July 2006.
8. NERC states that the revised
Reliability Standards were balloted in
September 2006 and were approved by
a weighted average of 74.5 percent with
81.6 percent of the ballot pool voting.
However, because negative comments
were received, a need for recirculation
of the ballot was triggered. The
recirculation ballot was conducted in
October 2006 and was approved by a
weighted average of 71.66 percent with
84.93 percent of the ballot pool voting.

1. Description of the Reliability
Standard
9. The stated Purpose of the
Reliability Standard is to ‘‘ensure that
System Operating Limits (SOLs) used in
the reliable planning of the Bulk Electric
System (BES) are determined based on
an established methodology or
methodologies.’’ 11 FAC–010–1 applies
to ‘‘planning authorities’’ and requires
each planning authority to document its
methods for determining system
operating limits and to share the
calculated limits with reliability
entities.12
10. Requirement R1 of the Reliability
Standard provides that the Planning
Authority shall have a documented SOL
methodology within its planning area
that is applicable to the planning time
horizon, does not exceed facility ratings,
and includes a description of how to
identify the subset of SOLs that qualify
as interconnection reliability operating
limits (IROLs).13
11. Requirement R2 of the Reliability
Standard identifies specific
considerations that must be included in
the methodology. For example,
Requirement R2.1 provides that the
methodology must include a
requirement that SOLs provide bulk
electric system performance so that, in
the pre-contingency state and with all
facilities in service, the bulk electric
system shall demonstrate transient,
dynamic and voltage stability and all
facilities shall be within their facility
ratings. Requirement R2.2 provides that,
following specified single
contingencies, the system shall
demonstrate transient, dynamic and
voltage stability, all facilities shall be
within their facility ratings, and

8 In Order No. 693, at P 1893–98, the Commission
approved the NERC glossary and directed specific
modifications to the document.
9 NERC filing at 20. Section 39.5(a) of the
Commission’s regulations, 18 CFR 39.5 (2007),
provides that the ERO’s submission of a new or
modified Reliability Standard must include, inter
alia, a concise statement of the basis and purpose
of the proposed Reliability Standard and a
demonstration that the proposal is just, reasonable
not unduly discriminatory or preferential, and in
the public interest. We note that NERC’s filing, at
20, includes a single paragraph describing the
purpose of the proposed Reliability Standards.
Future Reliability Standard filings may be subject
to a deficiency letter if they fail to satisfy the filing
requirements set forth in our regulations.
10 Id. at 21.

11 The NERC glossary defines system operating
limit or SOL as ‘‘the value * * * that satisfies the
most limiting of the prescribed operating criteria for
a specified system configuration to ensure operation
within acceptable reliability criteria.* * *’’
12 The NERC glossary defines ‘‘planning
authority’’ as ‘‘the responsible entity that
coordinates and integrates transmission facility and
service plans, resource plans, and protection
systems.’’ We note that Version 2 of NERC’s
Reliability Functional Model, adopted by the NERC
Board of Trustees on February 10, 2004, at 14–16,
discusses the role of the planning authority.
However, Version 3 of NERC’s Reliability
Functional Model, adopted by the NERC Board of
Trustees on February 13, 2007, at 13–15, appears to
have replaced ‘‘planning authority’’ with the new
term ‘‘planning coordinator.’’
13 As discussed later, NERC has proposed the
following definition of IROL, ‘‘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.’’

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II. Discussion
A. FAC–010–1 (System Operating Limits
Methodology for the Planning Horizon)

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cascading outages or uncontrolled
separation shall not occur. Requirement
R2.3 states that, starting with all
facilities in service, the system’s
response to a single contingency may
include any of the following:
R2.3.1—Planned or uncontrolled
interruption of electric supply to radial
customers or some local network
customers connected to or supplied by
the Faulted Facility or by the affected
area.
R2.3.2—System reconfiguration
through manual or automatic control or
protection actions.
R2.3.3—To prepare for the next
Contingency, system adjustments may
be made, including changes to
generation, uses of the transmission
system and the transmission system
topology.
12. Requirement R2.4 provides that,
starting with all facilities in service and
following any of the multiple
contingencies identified in Reliability
Standard TPL–003,14 the system shall
demonstrate transient, dynamic and
voltage stability, all facilities shall be
within their facility ratings, and
cascading outages or uncontrolled
separation shall not occur. Requirement
R2.5 states that, in determining the
response to any of the multiple
contingencies identified in TPL–003, in
addition to the actions identified in
R2.3.1 and R2.3.2, ‘‘the following shall
be acceptable: planned or controlled
interruption of electric supply to
customers (load shedding), the planned
removal from service of certain
generators, and/or the curtailment of
contracted Firm (non-recallable
reserved) electric power Transfers.’’
13. Further, FAC–010–1 includes an
Interconnection-wide regional
difference applicable to the Western
Interconnection. The regional difference
provides a different, more detailed
methodology for the evaluation of
multiple contingencies when
establishing SOLs. It also provides that
‘‘the Western Interconnection may make
changes (performance category
adjustments) to the Contingencies
required to be studied and/or the
required responses to Contingencies for
specific facilities based on actual system
performance and robust design.’’
14. Reliability Standard FAC–010–1
identifies data retention requirements
and two sets of Levels of NonCompliance, one of general applicability
and one for the Western
Interconnection. FAC–010–1 includes
14 In Order No. 693, the Commission approved
TPL–003–0. In addition, the Commission directed
the ERO to develop specific modifications to TPL–
003–0. See Order No. 693 at P 1816–25.

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Federal Register / Vol. 72, No. 160 / Monday, August 20, 2007 / Proposed Rules
Measures corresponding to each
Requirement. It identifies the regional
reliability organization as the entity
responsible for compliance monitoring.
2. Commission Proposal
15. The Commission proposes to
approve Reliability Standard FAC–010–
1 as a mandatory and enforceable
Reliability Standard.15 In addition, the
Commission seeks ERO clarification and
public comment on several matters
discussed below.
a. Consistency With Order No. 890
16. In Order No. 890, the Commission
amended the pro forma open access
transmission tariff (OATT) to ensure
that it achieves its original purpose of
remedying undue discrimination,
provide greater specificity to reduce
opportunities for undue discrimination,
and increase transparency in the rules
applicable to planning and use of the
transmission system.16 Order No. 890
requires the consistent use of
assumptions underlying operational
planning for short-term available
transmission capability (ATC)
calculations and expansion planning for
long-term ATC calculations.17
17. As explained above, FAC–010–1
requires each planning authority to
document its methods for determining
system operating limits or SOLs for the
planning horizon. SOLs often control or
define ATC by determining the outer
limit of the operational capability
between any two areas or across a
transmission path or interface. The
Commission seeks comment on whether
the development of a methodology for
calculation of SOLs for the planning
horizon pursuant to proposed
Reliability Standard FAC–010–1 and the
calculation of ATC for the long-term
pursuant to NERC’s Modeling, Data, and
Analysis (MOD) Reliability Standards
results in the consistent use of
assumptions as required by Order No.
890. In particular, the Commission has
the following concerns:

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(1) For a given set of conditions, the IROL
and SOL values will change with the
additional contingencies that are studied.
Application of additional first contingencies
and multiple contingencies will, in general,
result in lower SOL limits as compared to
those calculated with either the existing
operational or planning contingencies. Is
there a potential for the exercise of undue
15 The Commission expects that the reference to
the regional reliability organization as the
compliance monitor should be replaced with the
term Regional Entity. Order No. 693 at P 157.
16 Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890,
72 FR 12266 (March 15, 2007), FERC Stats. & Regs.
¶ 31,241 (2007), reh’g pending.
17 Id. P 290–95.

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discrimination against transmission
customers where, for example, a planning
authority’s SOL methodology calls for the
application of a single contingency in
determining SOLs pursuant to FAC–010–1
and the reliability coordinator and planning
authority calculate ATC for the long-term
using the assumption of multiple
contingencies? Do the Order No. 890
transparency requirements mitigate any
potential for the exercise of undue
discrimination in this respect?
(2) In Order No. 693, the Commission
required that total transfer capability (TTC)
be addressed under the Reliability Standard
that deals with transfer capability such as
FAC–012–1, rather than MOD–001–0.18 The
Commission disagreed with commenters
suggesting that transfer capabilities
addressed by FAC–012–1 are necessarily
different from TTC used for ATC calculation.
In a similar vein, the Commission seeks
comment on whether the SOLs developed
pursuant to FAC–010–1 are essentially the
same as TTC used for ATC calculation. If so,
should NERC address SOLs, transfer
capability and TTC in a coordinated and
consistent manner?

b. Western Interconnection Regional
Difference
18. Order No. 672 explains that
‘‘uniformity of Reliability Standards
should be the goal and the practice, the
rule rather than the exception.’’ 19
Moreover, the Commission has stated
that, as a general matter, regional
differences are permissible if they are
either more stringent than the continentwide Reliability Standard, or if they are
necessitated by a physical difference in
the Bulk-Power System.20 Regional
differences must still be just, reasonable,
not unduly discriminatory or
preferential and in the public interest.21
19. The WECC regional difference in
FAC–010–1 identifies a different list of
multiple contingencies from those in
Category C of Table 1 in the TPL
Reliability Standard series. The detailed
list of considerations in the regional
difference that would apply to the
Western Interconnection adds
additional contingencies and appears to
be more stringent. Thus, we also
propose to approve the regional
difference that would apply to the
Western Interconnection regarding the
methodology for establishing SOLs.
20. However, the Commission also
has the following concern regarding the
proposed regional difference. As noted
above, the regional difference provides
that the Western Interconnection may
make changes to the contingencies
required to be studied or required
responses to contingencies based on
18 See

Order No. 693 at P 1050–52.
19 Order No. 672 at P 290.
20 Id. P 291.
21 Id.

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actual system performance. Presumably,
such changes would be developed by
WECC. However, the Reliability
Standard does not identify any process
for making such changes or indicate
whether the requirements for reasonable
notice and opportunity for public
comment, due process, openness and
balance of interests will be met in
making such changes.22 Accordingly,
we propose that WECC should identify
the process that it will use to make
changes to the currently listed
contingencies required to be studied or
required responses to contingencies.
Further, the Commission seeks
comment on whether the regional
difference should be modified to
explicitly include the process that
WECC will use to make changes to the
currently listed contingencies.
c. Other Matters
21. The Commission seeks the
following clarification from the ERO
regarding the language of FAC–010–1.
As mentioned above, Requirement R2.3
provides that the system’s response to a
single contingency may include, inter
alia, ‘‘planned or controlled
interruption of electric supply to radial
customers or some local network
customers connected to or supplied by
the Faulted Facility or by the affected
area.’’ The Commission seeks
clarification whether this provision is
limited to the loss of load that is a direct
result of the contingency, i.e.,
consequential load, or whether this
provision allows firm load shedding and
firm transmission curtailment following
a single contingency. In Order No. 693,
the Commission determined that the
single contingency provision should
allow only the interruption of
consequential load 23 and seeks
confirmation from the ERO that this
proposed Reliability Standard conforms
to this determination.
22. Further, as noted above, while the
Reliability Standard identifies the
‘‘planning authority’’ as the applicable
entities, the most recent iteration of the
Functional Model has eliminated the
term and now refers to ‘‘planning
coordinator.’’ The ERO should explain
its plans to make FAC–010–1 consistent
with the most recent iteration of the
Functional Model, and how this may
affect the applicability of the Reliability
Standard to individual entities.24
22 See

16 U.S.C. 824o(c)(2)(D).
No. 693 at P 1791–94 (discussing TPL–

23 Order

002–0).
24 NERC’s Statement of Compliance Registry
Criteria (Version 3), approved by the Commission
in Order No. 693, sets out criteria that will be used
by NERC and the Regional Entities for identifying
Continued

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Finally, NERC must remove references
to the regional reliability organization as
the entity responsible for compliance
monitoring and replace it with either
the Regional Entity or ERO.25
23. Finally, Requirement R2.2 of
FAC–010–1 requires a planning
authority to consider various single
contingencies including the loss of a
shunt device. While the transmission
planning (TPL) Reliability Standards
implicitly require the consideration of
the loss of a shunt device, they do not
require this explicitly. Should the
Commission clarify the TPL Reliability
Standards by requiring the ERO to
modify them to explicitly require the
consideration of a shunt device,
consistent with FAC–010–1?
B. FAC–011–1 (System Operating Limits
Methodology for the Operations
Horizon)
1. Description of the Reliability
Standard
24. Proposed Reliability Standard
FAC–011–1 requires each reliability
coordinator to develop a SOL
methodology for determining which of
the stability limits associated with the
list of multiple contingencies are
applicable for use in the operating
horizon based on actual or expected
system conditions.
25. Requirement R2 of FAC–011–1
identifies specific considerations that
must be included in the methodology in
a pre-contingency state and following
one or multiple contingencies. The
provisions of Requirement R2 of FAC–
011–1 are the same as those in
Requirement R2 of FAC–010–1, except
for Requirement R2.3.2 of FAC–011–1,
which provides as follows:
In determining the system’s response to a
single Contingency, the following shall be
acceptable. * * * [i]nterruption of other
network customers, only if the system has
already been adjusted, or is being adjusted,
following at least one prior outage, or, if the
real-time operating conditions are more
adverse than anticipated in the
corresponding studies, e.g., load greater than
studied.

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26. FAC–011–1 includes an
Interconnection-wide regional
difference applicable to the Western
Interconnection, which repeats the
language of the regional difference in
users, owners and operators of the Bulk-Power
System that are candidates for registration for
compliance with mandatory Reliability Standards.
Order No. 693 at P 92–96. NERC’s registry criteria
provide that NERC will register entities that
perform a ‘‘planning authority’’ function. Thus, it
appears that the criteria used by NERC and the
Regional Entities to register entities are consistent
with the terms of FAC–010–1.
25 See Order No. 693 at P 157.

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FAC–010–1. Again, the regional
difference provides a different, more
detailed methodology for the evaluation
of multiple contingencies when
establishing SOLs. It also provides that
the ‘‘Western Interconnection may make
changes’’ to the contingencies required
to be studied and/or the required
responses to contingencies for specific
facilities.
27. Reliability Standard FAC–011–1
identifies data retention requirements
and two sets of Levels of NonCompliance, one of general applicability
and one for the Western
Interconnection. It includes Measures
corresponding to each Requirement and
identifies the regional reliability
organization as the entity responsible
for compliance monitoring.
2. Commission Proposal
28. The Commission proposes to
approve Reliability Standard FAC–011–
1 as a mandatory and enforceable
Reliability Standard. In addition, the
Commission seeks ERO clarification and
public comment on several matters
discussed below.
a. Consistency With Order No. 890
29. Similar to our concerns discussed
above regarding FAC–010–1, the
Commission has the following concerns:
(1) Is there a potential for the exercise of
undue discrimination against transmission
customers where, for example, a reliability
coordinator’s SOL methodology calls for the
application of a single contingency in
determining SOLs pursuant to FAC–011–1
and the reliability coordinator and planning
authority calculate ATC for the short-term
using the assumption of multiple
contingencies? Do the Order No. 890
transparency requirements mitigate any
potential for the exercise of undue
discrimination in this respect?
(2) In Order No. 693, the Commission
required that TTC be addressed under the
Reliability Standard that deals with transfer
capability such as FAC–012–1, rather than
MOD–001–0.26 The Commission disagreed
with commenters suggesting that transfer
capabilities addressed by FAC–012–1 are
necessarily different from TTC used for ATC
calculation. In a similar vein, the
Commission seeks comment on whether the
SOLs developed pursuant to FAC–011–1 are
essentially the same as TTC used for ATC
calculation. If so, should NERC address
SOLs, transfer capability and TTC in a
coordinated and consistent manner?

b. Western Interconnection Regional
Difference
30. The detailed list of considerations
in the regional difference that would
apply to the Western Interconnection
appears to be more stringent and

detailed than the set of contingencies
provided in Requirement R2 of FAC–
011–1. Thus, we also propose to
approve the regional difference that
would apply to the Western
Interconnection regarding the
methodology for the evaluation of
multiple facility contingencies when
establishing SOLs.
31. Similar to our discussion
regarding FAC–010–1, the Commission
is concerned that the regional difference
provides that the Western
Interconnection may make changes to
the contingencies required to be studied
or required responses to contingencies
based on actual system performance.
Presumably, such change would be
developed by WECC. However, the
Reliability Standard does not identify
any process for making such changes or
indicate whether the requirements for
reasonable notice and opportunity for
public comment, due process, openness
and balance of interests will be met in
making such changes.27 Accordingly,
we propose that WECC should identify
the process that it will use to make
changes to the currently listed
contingencies required to be studied or
required responses to contingencies.
Further, the Commission seeks
comment on whether the regional
difference should be modified to
explicitly include the process that
WECC will use to make changes to the
currently listed contingencies.
c. Other Matters
32. As mentioned above, Requirement
R2.3.2 provides that the system’s
response to a single contingency may
include, inter alia, ‘‘[i]nterruption of
other network customers, only if the
system has already been adjusted, or is
being adjusted, following at least one
prior outage, or, if the real-time
operating conditions are more adverse
than anticipated in the corresponding
studies, e.g., load greater than studied.’’
The Commission seeks clarification
from the ERO regarding the meaning of
the phrase ‘‘if the real-time operating
conditions are more adverse than
anticipated in the corresponding
studies, e.g., load greater than studied.’’
In particular, the Commission is
concerned whether this provision treats
load forecast error as a contingency and
as such would allow an interruption
due to an inaccurate weather forecast.
Finally, NERC must remove references
to the regional reliability organization as
the entity responsible for compliance
monitoring and replace it with either
the Regional Entity or ERO.28
27 See

26 See

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33. Requirement R2.2 of FAC–011–1
requires a reliability coordinator to
consider various single contingencies
including the loss of a shunt device.
While the TPL Reliability Standards
implicitly require the consideration of
the loss of a shunt device, they do not
require this explicitly. Should the TPL
Reliability Standards be modified to
explicitly require the consideration of a
shunt device, consistent with FAC–011–
1?

accordance with consistent
methodologies. However, NERC must
remove references to the regional
reliability organization as the entity
responsible for compliance monitoring
and replace it with either the Regional
Entity or ERO.29

C. FAC–014–1 (Establish and
Communicate System Operating Limits)

Cascading Outages: The uncontrolled
successive loss of bulk electric system
facilities triggered by an incident (or
condition) at any location resulting in the
interruption of electric service that cannot be
restrained from spreading beyond a predetermined area.
Delayed Fault Clearing: Fault clearing
consistent with correct operation of a breaker
failure protection system and its associated
breakers, or of a backup protection system
with an intentional time delay.
Interconnection Reliability Operating Limit
(IROL): 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.
Interconnection Reliability Operating Limit
Tv (IROL Tv): The maximum time that an
Interconnection Reliability Operating Limit
can be violated before the risk to the
interconnection or other Reliability
Coordinator Area(s) becomes greater than
acceptable. Each Interconnection Reliability
Operating Limit’s Tv shall be less than or
equal to 30 minutes.

1. Description of the Reliability
Standard
34. Proposed Reliability Standard
FAC–014–1 requires each reliability
coordinator, planning authority,
transmission planner and transmission
operator to develop and communicate
SOL limits in accordance with the
methodologies developed pursuant to
FAC–010–1 and FAC–011–1.
35. Requirement R1 requires the
reliability coordinator to ensure that
SOLs are established for its ‘‘reliability
coordinator area’’ and that the SOLs are
consistent with its SOL methodology.
Requirement R2 requires the
transmission operator to establish SOLs
as directed by its reliability coordinator
that are consistent with the reliability
coordinator’s methodology. Likewise,
Requirements R3 and R4 require the
planning authority and transmission
planner, respectively, to establish SOLs
consistent with the planning authority’s
SOL methodology. Requirement R5
requires the reliability coordinator,
planning authority and transmission
planner to provide its SOLs to those
entities that have a reliability-related
need. Finally, Requirement R6 requires
the planning authority to identify the
subset of multiple contingencies, if any,
from Reliability Standard TPL–003
which result in stability limits and to
provide this list and associated stability
limits to the relevant reliability
coordinator.
36. Reliability Standard FAC–014–1
includes data retention requirements,
Levels of Non-Compliance, and
Measures corresponding to each
Requirement. It identifies the regional
reliability organization as the entity
responsible for compliance monitoring.
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2. Commission Proposal
37. The Commission proposes to
approve Reliability Standard FAC–014–
1 as a mandatory and enforceable
Reliability Standard. The Reliability
Standard fulfills an important reliability
goal in the development and
communication of SOL limits in

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D. Proposed Definitions
38. NERC proposes the addition or
revision of the following four terms in
the NERC glossary:

39. The Commission believes that
there could be multiple interpretations
of some of these terms. As such, the
Commission proposes to provide its
clarification of Cascading Outages,
Interconnection Reliability Operating
Limit, and Interconnection Reliability
Operating Limit TV to be consistent with
directives in Order No. 693.
40. The current definition of
Cascading Outages in the approved
NERC glossary is ‘‘The uncontrolled
successive loss of system elements
triggered by an incident at any location.
Cascading results in widespread electric
service interruption that cannot be
restrained from sequentially spreading
beyond an area predetermined by
studies.’’ 30 The ambiguity in the term
relates to the last phrase in the
definition which identifies the extent of
an outage that would be considered a
cascade. The revised definition uses the
similar phrase ‘‘a predetermined area’’
which may lead to different
interpretations. The Commission
understands that this phrase has been
29 See

Order No. 693 at P 157.
April 4, 2006 Request for Approval of
Reliability Standards, Glossary of Terms Used in
Reliability Standards at 2.

interpreted as being as small as the
elements that would be removed from
service by local protective relays to as
large as the entire balancing authority.
Simply put, some applications of
Cascading Outage could allow the loss
of an entire balancing authority and not
consider that loss to be a Cascading
Outage. The Commission disagrees with
such a liberal application. For purposes
of compliance, the Commission
proposes to direct NERC to consider the
loss of facilities in the bulk electric
systems that are beyond those that
would be removed from service by
primary or backup protective relaying
associated with the initiating event to be
a Cascading Outage. With this
understanding of the phrase, the
Commission proposes to accept the
definition in FAC–014.
41. With respect to NERC’s proposed
definition of IROL, the Commission
identified in Order No. 693 that the
statutory definition of Reliable
Operation is to assure that the system is
operated within thermal, voltage and
stability limits such that instability,
uncontrolled separation, or cascading
failures will not occur. IROLs are a
specific subset of the operating limits at
which instability, uncontrolled
separation, or cascading failures may
occur. All IROL violations will have an
adverse impact on the reliability of the
bulk electric system.
42. The definition of IROL in the
approved NERC glossary is ‘‘The value
(such as MW, MVar, Amperes,
Frequency or Volts) derived from, or a
subset of the System Operating Limits,
which if exceeded, could expose a
widespread area of the Bulk Electric
System to instability, uncontrolled
separation(s) or cascading outages.’’ 31
The revised definition is consistent with
the intent of the statute with the
exception of the phrase ‘‘that adversely
impacts the reliability of the bulk
electric system.’’ This may give the
impression that violation of some IROLs
that do not adversely impact the
reliability of the bulk electric system are
acceptable. The Commission proposes
to accept the definition in FAC–014
with the understanding that all IROLs
impact bulk electric system reliability.
43. In Order No. 693, the Commission
identified two interpretations of when
an entity exceeds an IROL.32 The
definition of IROL Tv does not
distinguish between those two
interpretations. The Commission
proposes to accept the definition in
FAC–014 with the understanding that
the only time it is acceptable to violate

30 NERC

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31 Id.

at 7.
Order No. 693 at P 946 & n.303.

32 See

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an IROL is in the limited time after a
contingency has occurred and the
operators are taking action to eliminate
the violation.

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E. Violation Risk Factors
44. As part of its compliance and
enforcement program, NERC plans to
assign a low, medium or high Violation
Risk Factor to each requirement of each
mandatory Reliability Standard to
associate a violation of the requirement
with its potential impact on the
reliability of the Bulk-Power System.
The categories are based on the
following definitions:
High Risk Requirement: (a) Is a
requirement that, if violated, could directly
cause or contribute to Bulk-Power System
instability, separation, or a cascading
sequence of failures, or could place the BulkPower System at an unacceptable risk of
instability, separation, or cascading failures;
or (b) is a requirement in a planning timeframe that, if violated, could, under
emergency, abnormal, or restorative
conditions anticipated by the preparations,
directly cause or contribute to Bulk-Power
System instability, separation, or a cascading
sequence of failures, or could place the BulkPower System at an unacceptable risk of
instability, separation, or cascading failures,
or could hinder restoration to a normal
condition.
Medium Risk Requirement: (a) Is a
requirement that, if violated, could directly
affect the electrical state or the capability of
the Bulk-Power System, or the ability to
effectively monitor and control the BulkPower System, but is unlikely to lead to
Bulk-Power System instability, separation, or
cascading failures; or (b) is a requirement in
a planning time frame that, if violated, could,
under emergency, abnormal, or restorative
conditions anticipated by the preparations,
directly affect the electrical state or capability
of the Bulk-Power System, or the ability to
effectively monitor, control, or restore the
Bulk-Power System, but is unlikely, under
emergency, abnormal, or restoration
conditions anticipated by the preparations, to
lead to Bulk-Power System instability,
separation, or cascading failures, nor to
hinder restoration to a normal condition.
Lower Risk Requirement: Is administrative
in nature and (a) is a requirement that, if
violated, would not be expected to affect the
electrical state or capability of the BulkPower System, or the ability to effectively
monitor and control the Bulk-Power System;
or (b) is a requirement in a planning time
frame that, if violated, would not, under the
emergency, abnormal, or restorative
conditions anticipated by the preparations,
be expected to affect the electrical state or
capability of the Bulk-Power System, or the
ability to effectively monitor, control, or
restore the Bulk-Power System.33

45. In a separate filing, NERC
identified Violation Risk Factors for
33 North American Electric Reliability Corp., 119
FERC ¶ 61,145 at P 9 (2007) (Violation Risk Factor
Order).

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each Requirement of proposed
Reliability Standards FAC–010–1, FAC–
011–1 and FAC–014–1.34 NERC
requested that the Commission approve
the Violation Risk Factors when it takes
action on the associated Reliability
Standards.
46. In the Violation Risk Factor Order,
the Commission addressed Violation
Risk Factors filed by NERC for Version
0 and Version 1 Reliability Standards. In
that order, the Commission used five
guidelines for evaluating the validity of
each Violation Risk Factor assignment:
(1) Consistency with the conclusions of
the Final Report on the August 14, 2003
blackout in the United States and
Canada,35 (2) consistency within a
Reliability Standard, (3) consistency
among Reliability Standards with
similar Requirements, (4) consistency
with NERC’s proposed definition of the
Violation Risk Factor level, and (5)
assignment of Violation Risk Factor
levels to those Requirements in certain
Reliability Standards that co-mingle a
higher risk reliability objective and a
lower risk reliability objective.36
47. The Commission proposes to
approve most of the Violation Risk
Factors for Reliability Standards FAC–
010–1, FAC–011–1 and FAC–014–1 that
NERC identified in its March 23, 2007
filing. However, several of the Violation
Risk Factors submitted for Reliability
Standards FAC–010–1, FAC–011–1 and
FAC–014–1 raise concerns. First, the
Commission notes that there are no
Violation Risk Factors applicable to the
WECC regional differences and that
certain portions of the WECC regional
differences lack levels of noncompliance. The Commission requests
comment on whether it should require
WECC to develop Violation Risk Factors
and the levels of non-compliance for the
regional differences. If so, we request
comment on how WECC should assess
penalties in the interim.
48. In FAC–010–1, the Commission
proposes to direct NERC to modify the
lower Violation Risk Factor assigned to
Requirement R2 and the medium
34 See NERC March 23, 2007 Request for
Approval of Violation Risk Factors for Version 1
Reliability Standards, Docket No. RR07–10–000,
Exh. A, Violation Risk Factors for Facility Ratings
Standards FAC–008–1 through FAC–014–1. The
Commission addressed only those Violation Risk
Factors pertaining to the 83 Reliability Standards
approved in Order No. 693. Violation Risk Factor
Order, 119 FERC ¶ 61,145 (2007).
35 U.S.-Canada Power System Outage Task Force
(Task Force), Final Report on the August 14, 2003
Blackout in the United States and Canada: Causes
and Recommendations (April 2004) (Final Blackout
Report). The Final Blackout Report is available on
the Internet at http://www.ferc.gov/industries/
electric/indus-act/blackout.asp.
36 For a complete discussion of each factor, see
the Violation Risk Factor Order at P 19–36.

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Violation Risk Factor assigned to subRequirements R2.1–R2.2.3 based on
guideline (4), which was developed to
evaluate whether the assignment of a
particular Violation Risk Factor level
conforms to NERC’s definition of that
risk level.
49. FAC–010–1 Requirement R2
requires the Planning Authority’s SOL
methodology to include a requirement
that SOLs provide bulk electric system
performance consistent with a stable
pre-contingency (sub-Requirement R2.1)
and post-contingency (subRequirements R2.2–R2.2.3) bulk electric
system using an accurate system
topology with all facilities operating
within their ratings and without postcontingency cascading outages or
uncontrolled separation.
50. NERC has assigned a lower
Violation Risk Factor to Requirement
R2.1, which requires the bulk electric
system in a pre-contingency state and
with all facilities in service to
demonstrate transient, dynamic and
voltage stability. The Commission
believes that the lower assignment is
inappropriate. A violation of a lower
Violation Risk Factor, by definition, is
generally considered administrative in
nature and would not be expected to
affect the electrical state or capability of
the Bulk-Power System, or the ability to
effectively monitor, control or restore
the Bulk-Power System.37 The
Commission believes that the lower
Violation Risk Factor NERC proposes for
this Requirement is not consistent with
the ‘‘lower’’ definition, but consistent
with the definition of ‘‘high.’’ The
Commission believes that a violation of
Requirement R2.1 could directly cause
or contribute to Bulk-Power System
instability, separation or cascading
failures since a violation of R2.1 means
that the system is in an unreliable state
even before the system is subject to
respond to a contingency. Therefore, we
propose to require NERC to change the
Violation Risk Factor of R.2.1 to high.
51. Similarly, NERC assigns a medium
violation Risk Factor to FAC–010–1
R2.2, which would be appropriate if a
violation is unlikely to lead to BulkPower System instability, separation or
cascading failures.38 However,
Requirement R2.2 specifically states that
with regard to post-contingency bulk
electric system performance,
‘‘[c]ascading outages or uncontrolled
separation shall not occur.’’ Therefore, if
Requirement R2.2 is violated for any
one of the specific contingencies as
described in Requirements R2.2.1–
37 See

id.
Violation Risk Factor Order, 119 FERC
¶ 61,145 at P 9.
38 See

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R2.2.3, cascading outages or
uncontrolled separation of the BulkPower System may occur. The potential
risk a violation of R2.2 poses to the
Bulk-Power System is not consistent
with the definition of a medium
Violation Risk Factor. Instead, the risk
a violation of R2.2 presents to the BulkPower System is consistent with the
definition of a high Violation Risk
Factor.39 Therefore, we propose to
require NERC to change the Violation
Risk Factor of R.2.2 to high.
52. As stated in the Violation Risk
Factor Order, the Commission expects a
rational connection between the subRequirement Violation Risk Factor
assignments and the main Requirement
Violation Risk Factor assignment.40
Because the Commission proposes to
require NERC to modify the Violation
Risk Factors for the sub-requirements of
R2, to have a rational connection
between the Violation Risk Factors
assigned to sub-Requirements and
Violation Risk Factors assigned to the
main Requirement, we are also
proposing to require NERC to change
the Violation Risk Factor for R2 to high.
53. Similarly, the Commission has the
same concern and proposal to reassign
NERC’s Violation Risk Factors for FAC–
011–1 Requirement R2 and subRequirements R2.1–R2.2.3, which
contain similar language as the
corresponding Requirements in FAC–
010–1.
54. With regard to FAC–014–1, our
concerns are with NERC’s proposed
Violation Risk Factor assignment of
medium to Requirement R5 and subRequirements R5.1–R5.1.4. Requirement
R5 requires that the reliability
coordinator, planning authority and
transmission planner 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. Sub-Requirements R5.1–R5.1.4
comprise the list of supporting
information to be provided. The
Commission has concerns with NERC’s
proposed assignment based on its lack
of consistency with the Final Blackout
Report.
55. The Commission believes that it is
important to ensure that critical areas
identified as causes of the August 2003
and other previous major blackouts are
appropriately assigned as potential risks
to the reliability of the Bulk-Power
System.41 For example, the Final
Blackout Report identified ineffective
communications as one common factor
39 See

id.
P 22.
41 Id. P 19–21.
40 Id.

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of the August 2003 blackout and other
previous major blackouts.42 The Final
Blackout Report explained that,
‘‘[u]nder normal conditions, parties
with reliability responsibility need to
communicate important and prioritized
information to each other in a timely
way, to help preserve the integrity of the
grid.’’ 43
56. The Commission believes that
NERC’s proposed Violation Risk Factor
assignment of medium for the subject
Requirements is not consistent with the
findings of the Final Blackout Report.
By definition, a ‘‘medium’’ Violation
Risk Factor designation means that a
violation of the requirement is unlikely
to lead to Bulk-Power System
instability, separation or cascading
failures.44 Findings of the Final
Blackout Report, as well as reports on
other previous major blackouts, have
determined otherwise in that the timely
communication of important and
prioritized information, in this case,
SOLs and IROLs, to entities that have a
reliability-related need for those limits
are crucial in maintaining the reliability
of the Bulk-Power System.
57. As a result, we propose to require
NERC to assign FAC–014–1
Requirement R5, as well as subRequirements R5.1–R5.1.4, a high
Violation Risk Factor to accurately
reflect the potential risk a violation of
the subject requirements presents to the
Bulk-Power System.
III. Information Collection Statement
58. The Office of Management and
Budget (OMB) regulations require
approval of certain information
collection requirements imposed by
agency rules.45 Upon approval of a
collection(s) of information, OMB will
assign an OMB control number and an
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.
The Paperwork Reduction Act (PRA) 46
requires each federal agency to seek and
obtain OMB approval before
undertaking a collection of information
directed to ten or more persons, or
continuing a collection for which OMB
approval and validity of the control
number are about to expire.47 The PRA
defines the phrase ‘‘collection of
information’’ to be the ‘‘obtaining,
42 Final

Blackout Report at 107.
at 109.
44 Violation Risk Factor Order, P 9.
45 5 CFR 1320.13 (2007).
46 44 U.S.C. 3501–3520.
47 44 U.S.C. 3502(3)(A)(i), 44 U.S.C. 3507(a)(3).
43 Id.

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causing to be obtained, soliciting, or
requiring the disclosure to third parties
or the public, of facts or opinions by or
for an agency, regardless of form or
format, calling for either—
(i) Answers to identical questions posed to,
or identical reporting or recordkeeping
requirements imposed on ten or more
persons, other than agencies,
instrumentalities, or employees of the United
States; or (ii) answers to questions posed to
agencies, instrumentalities, or employees of
the United States which are to be used for
general statistical purposes.’’ 48

59. This NOPR proposes to approve
three new Reliability Standards
developed by NERC as the ERO. Section
215 of the FPA authorizes the ERO to
develop Reliability Standards to provide
for the operation of the Bulk-Power
System. Pursuant to the statute, the ERO
must submit each Reliability Standard
that it proposes to be made effective to
the Commission for approval.49
60. The three proposed Reliability
Standards do not require responsible
entities to file information with the
Commission. Nor, with the exception of
a three year self-certification of
compliance, do the Reliability
Standards require responsible entities to
file information with the ERO or
Regional Entities. However, the
Reliability Standards do require
responsible entities to develop and
maintain certain information for a
specified period of time, subject to
inspection by the ERO or Regional
Entities. Reliability Standard FAC–010–
1 requires the planning authority to
have a documented methodology for use
in developing system operating limits or
SOLs and must retain evidence that it
issued its SOL methodology to relevant
reliability coordinators, transmission
operators and adjacent planning
authorities. Likewise, the planning
authority must respond to technical
comments on the methodology within
45 days of receipt. Further, each
planning authority must self-certify its
compliance to the compliance monitor
once every three years. Reliability
Standard FAC–011–1 requires similar
documentation by the reliability
coordinator.
61. Reliability Standard FAC–014–1
requires the reliability coordinator,
planning authority, transmission
operator, and transmission planner to
verify compliance through selfcertification submitted to the
compliance monitor annually. These
entities must also document that they
have developed SOLs consistent with
the applicable SOL methodology and
48 44

U.S.C. 3502(3)(A).
16 U.S.C. 824o(d).

49 See

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that they have provided SOLs to entities
identified in Requirement 5 of the
Reliability Standard. Further, the
planning authority must maintain a list
of multiple contingencies and their
associated stability limits.
62. 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. Comments
are solicited on the Commission’s need
for this information, whether the
information will have practical utility,
the accuracy of provided burden
estimates, ways to enhance the quality,

utility, and clarity of the information to
be collected, and any suggested methods
for minimizing the respondent’s burden,
including the use of automated
information techniques.
63. Our Estimates below regarding the
number of respondents is based on the
NERC compliance registry as of April
2007. NERC and the Regional Entities
have identified approximately 170
Investor Owned Utilities, and 80 Large
Municipals and Cooperatives. NERC’s
compliance registry indicates that there
is a significant amount of overlap among
the entities that perform these functions.
In some instances, a single entity may
Number of
respondents

Data collection

Number of
responses

be registered under all four of these
functions. Thus, the Commission
estimates that the total number of
entities required to comply with the
information ‘‘reporting’’ or development
requirements of the proposed Reliability
Standards is approximately 250 entities.
About two-thirds of these entities are
investor-owned utilities and one-third is
a combination of municipal and
cooperative organizations.
64. Burden Estimate: The Public
Reporting burden for the requirements
contained in the NOPR is as follows:

Hours per respondent

Total annual hours

FERC–725D
Investor-Owned Utilities ..................................
Large Municipals and Cooperatives ...............

170
........................
80
........................

1
........................
1
........................

Reporting: 90 .........................
Recordkeeping: 210 ...............
Reporting: 90 .........................
Recordkeeping: 210 ...............

Reporting: 15,300.
Recordkeeping: 35,700.
Reporting: 7,200.
Recordkeeping: 16,800.

250

........................

................................................

75,000.

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Total .........................................................

Total Hours: (Reporting 22,500 hours
+ Recordkeeping 52,500 hours) = 75,000
hours.
(FTE=Full Time Equivalent or 2,080
hours)
Total Annual hours for Collection:
(Reporting + recordkeeping) = 75,000
hours.
Information Collection Costs: The
Commission seeks comments on the
costs to comply with these
requirements. It has projected the
average annualized cost to be the total
annual hours (reporting) 22,500 times
$120 = $2,700,000.
Recordkeeping = 52,500 @ $40/hour =
$2,100,000.
Labor (file/record clerk @ $17 an hour
+ supervisory @23 an hour).
Storage 1,800 sq. ft. × $925 (off site
storage) = $1,665,000.
Total costs = $6,465,000.
The Commission believes that this
estimate may be conservative because
most if not all of the applicable entities
currently perform SOL calculations and
the proposed Reliability Standards will
provide a common methodology for
those calculations.
Title: FERC–725D Facilities Design,
Connections and Maintenance
Reliability Standards.
Action: Proposed Collection of
Information.
OMB Control No.: To be determined.
Respondents: Business or other for
profit, and/or not for profit institutions.
Frequency of Responses: One time to
initially comply with the rule, and then
on occasion as needed to revise or

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modify. In addition, annual and threeyear self-certification requirements will
apply.
Necessity of the Information: The
three Reliability Standards, if adopted,
would implement 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 three proposed
Reliability Standards would ensure that
system operating limits or SOLs used in
the reliability planning and operation of
the Bulk-Power System are determined
based on an established methodology.
Internal review: The Commission has
reviewed the requirements pertaining to
mandatory Reliability Standards for the
Bulk-Power System and determined the
proposed requirements are necessary to
meet the statutory provisions of the
Energy Policy Act of 2005. These
requirements conform to the
Commission’s plan for efficient
information collection, communication
and management within the energy
industry. The Commission has assured
itself, by means of internal review, that
there is specific, objective support for
the burden estimates associated with the
information requirements.
65. Interested persons may obtain
information on the reporting
requirements by contacting: Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426
[Attention: Michael Miller, Office of the
Executive Director, Phone: (202) 502–

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8415, fax: (202) 273–0873, e-mail:
[email protected]]. Comments on
the requirements of the proposed rule
may also be sent to the Office of
Information and Regulatory Affairs,
Office of Management and Budget,
Washington, DC 20503 [Attention: Desk
Officer for the Federal Energy
Regulatory Commission], e-mail:
[email protected].
IV. Environmental Analysis
66. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.50 The Commission has
categorically excluded certain actions
from this requirement as not having a
significant effect on the human
environment. The actions proposed here
fall within the categorical exclusion in
the Commission’s regulations for rules
that are clarifying, corrective or
procedural, for information gathering,
analysis, and dissemination.51
Accordingly, neither an environmental
impact statement nor environmental
assessment is required.

50 Order No. 486, Regulations Implementing the
National Environmental Policy Act, 52 FR 47897
(Dec. 17, 1987), FERC Stats. & Regs. Regulations
Preambles 1986–1990 ¶ 30,783 (1987).
51 18 CFR 380.4(a)(5) (2007).

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Federal Register / Vol. 72, No. 160 / Monday, August 20, 2007 / Proposed Rules
V. Regulatory Flexibility Act
Certification
67. The Regulatory Flexibility Act of
1980 (RFA) 52 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. Most of the entities, i.e.,
planning authorities, reliability
coordinators, transmission planners and
transmission operators, to which the
requirements of this rule would apply
do not fall within the definition of small
entities.53
68. As indicated above, based on
available information regarding NERC’s
compliance registry, approximately 250
entities will be responsible for
compliance with the three new
Reliability Standards. It is estimated
that one-third of the responsible
entities, about 80 entities, would be
municipal and cooperative
organizations. The proposed Reliability
Standards would apply to planning
authorities, transmission planners,
transmission operators and reliability
coordinators, which tend to be larger
entities. Thus, the Commission believes
that only a portion, approximately 30 to
40 of the municipal and cooperative
organizations to which the proposed
Reliability Standards would apply,
qualify as small entities.54 The
Commission does not consider this a
substantial number. Moreover, as
discussed above, the proposed
Reliability Standards will not be a
burden on the industry since most if not
all of the applicable entities currently
perform SOL calculations and the
proposed Reliability Standards will
simply provide a common methodology
for those calculations. Accordingly, the
Commission certifies that the proposed
Reliability Standards will not have a
52 5

U.S.C. 601–612.
RFA definition of ‘‘small entity’’ refers to
the definition provided in the Small Business Act,
which defines a ‘‘small business concern’’ as a
business that is independently owned and operated
and that is not dominant in its field of operation.
See 15 U.S.C. 632 (2000). According to the SBA, a
small electric utility is defined as one that has a
total electric output of less than four million MWh
in the preceding year.
54 According to the DOE’s Energy Information
Administration (EIA), there were 3,284 electric
utility companies in the United States in 2005, and
3,029 of these electric utilities qualify as small
entities under the SBA definition. Among these
3,284 electric utility companies are: (1) 883
cooperatives of which 852 are small entity
cooperatives; (2) 1,862 municipal utilities, of which
1842 are small entity municipal utilities; (3) 127
political subdivisions, of which 114 are small entity
political subdivisions; and (4) 219 privately owned
utilities, of which 104 could be considered small
entity private utilities. See Energy Information
Administration Database, Form EIA–861, Dept. of
Energy (2005), available at http://www.eia.doe.gov/
cneaf/electricity/page/eia861.html.

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significant adverse impact on a
substantial number of small entities.
69. Based on this understanding, the
Commission certifies that this rule will
not have a significant economic impact
on a substantial number of small
entities. Accordingly, no regulatory
flexibility analysis is required.
VI. Comment Procedures
70. The Commission invites interested
persons to submit comments on the
matters and issues proposed in this
notice to be adopted, including any
related matters or alternative proposals
that commenters may wish to discuss.
Comments are due September 19, 2007.
Comments must refer to Docket No.
RM07–3–000, and must include the
commenter’s name, the organization
they represent, if applicable, and their
address in their comments. Comments
may be filed either in electronic or
paper format.
71. Comments may be filed
electronically via the eFiling link on the
Commission’s Web site at http://
www.ferc.gov. The Commission accepts
most standard word processing formats
and commenters may attach additional
files with supporting information in
certain other file formats. Commenters
filing electronically do not need to make
a paper filing. Commenters that are not
able to file comments electronically
must send an original and 14 copies of
their comments to: Federal Energy
Regulatory Commission, Office of the
Secretary, 888 First Street, NE.,
Washington, DC 20426.
72. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters.
VII. Document Availability
73. 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 p.m. Eastern time) at 888 First
Street, NE., Room 2A, Washington, DC
20426.
74. 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

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46421

docket number excluding the last three
digits of this document in the docket
number field.
75. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from our Help
line at (202) 502–8222 or the Public
Reference Room at (202) 502–8371 Press
0, TTY (202) 502–8659. E-Mail the
Public Reference Room at
[email protected].
By direction of the Commission.
Kimberly D. Bose,
Secretary.
[FR Doc. E7–16253 Filed 8–17–07; 8:45 am]
BILLING CODE 6717–01–P

DEPARTMENT OF THE TREASURY
Internal Revenue Service
26 CFR Part 1
[REG–148393–06]
RIN 1545–BG12

Medical and Accident Insurance
Benefits Under Qualified Plans
Internal Revenue Service (IRS),
Treasury.
ACTION: Notice of proposed rulemaking
and notice of public hearing.
AGENCY:

SUMMARY: This document contains
proposed regulations under section
402(a) of the Internal Revenue Code
(Code) regarding the tax treatment of
payments by qualified plans for medical
or accident insurance. These regulations
would affect administrators of,
participants in, and beneficiaries of
qualified retirement plans. This
document also provides notice of a
public hearing on these proposed
regulations.

Written or electronic comments
must be received by November 19, 2007.
Outlines of topics to be discussed at the
public hearing scheduled for December
6, 2007, at 10 a.m., must be received by
November 15, 2007.
ADDRESSES: Send submissions to:
CC:PA:LPD:PR (REG–148393–06), room
5203, Internal Revenue Service, P.O.
Box 7604, Ben Franklin Station,
Washington, DC 20044. Submissions
may be hand-delivered Monday through
Friday between the hours of 8 a.m. and
4 p.m. to CC:PA:LPD:PR (REG–148393–
06), Courier’s Desk, Internal Revenue
Service, 1111 Constitution Avenue,
NW., Washington, DC, or send
electronically via the Federal
eRulemaking Portal at http://
www.regulations.gov (IRS REG–148393–
06). The public hearing will be held in
DATES:

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