Federal Register notice NOPR

06-8927.pdf

Mandatory Reliability Standards for the Bulk-Power System

Federal Register notice NOPR

OMB: 1902-0244

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Friday,
November 3, 2006

Part II

Department of
Energy
Federal Energy Regulatory Commission

sroberts on PROD1PC70 with PROPOSALS

18 CFR Part 40
Mandatory Reliability Standards for the
Bulk-Power System; Proposed Rule

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Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
Docket No. RM06–16–000]

Mandatory Reliability Standards for the
Bulk-Power System
October 20, 2006.

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

Pursuant to section 215 of the
Federal Power Act (FPA), the
Commission is proposing to approve 83
of 107 proposed Reliability Standards,
including six of the eight regional
differences, and the Glossary of Terms
Used in Reliability Standards developed
by the North American Electric
Reliability Council, on behalf of its
wholly-owned subsidiary, the North
American Electric Reliability
Corporation (NERC), which the
Commission has certified as the Electric
Reliability Organization (ERO)
responsible for developing and
enforcing mandatory Reliability
Standards. Those Reliability Standards
meet the requirements of section 215 of
the FPA and Part 39 of the
Commission’s regulations. However,
although we believe it is in the public
interest to make these Reliability
Standards mandatory and enforceable
by June 2007, we also find that much
work remains to be done. Specifically,
SUMMARY:

we believe that many of these Reliability
Standards require significant
improvement to address, among other
things, the recommendations of the
Blackout Report. We therefore propose,
pursuant to section 215(d)(5), to require
the ERO to make significant
improvements to many of the 83
Reliability Standards that are being
approved as mandatory and enforceable.
Appendix D provides a list of the
Reliability Standards that should be
given the highest priority when the ERO
undertakes to make these
improvements. With respect to the
remaining 24 Reliability Standards, the
Commission proposes that they remain
pending at the Commission until further
information is provided. The
Commission is not proposing to remand
any Reliability Standards.
The Commission proposes to amend
the text of its regulation to require that
each Reliability Standard identify the
subset of users, owners and operators to
which that particular Reliability
Standard applies. The Commission also
is proposing to amend its regulations to
require that each Reliability Standard
that is approved by the Commission will
be maintained in the Commission’s
Public Reference Room and on the
ERO’s Internet Web site for public
inspection.
DATES: Comments are due January 2,
2007.
ADDRESSES: You may submit comments,
identified by Docket No. RM06–16–000,
by one of the following methods:
• Agency Web site: http://ferc.gov.
Follow the instructions for submitting

comments via the eFiling link found in
the Comment Procedures section of the
Preamble.
• Mail: Commenters unable to file
comments electronically must mail or
hand deliver an original and 14 copies
of their comments to: Federal Energy
Regulatory Commission, Office of the
Secretary, 888 First Street. NE.,
Washington, DC 20426. Refer to the
Comment Procedures section of the
preamble for additional information on
how to file paper comments.
FOR FURTHER INFORMATION CONTACT:

Jonathan First (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–8529.
Paul Silverman (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–8683.
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 Market
and Reliability, Division of Policy
Analysis and Rulemaking, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–8923.
SUPPLEMENTARY INFORMATION:

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Paragraph
Numbers
I. Introduction .........................................................................................................................................................................................
II. Background .........................................................................................................................................................................................
A. Voluntary Reliability Standards ................................................................................................................................................
B. EPAct 2005 and Order No. 672 .................................................................................................................................................
C. The Electric Reliability Organization ........................................................................................................................................
D. NERC Petition for Approval of Reliability Standards ..............................................................................................................
E. Staff Preliminary Assessment .....................................................................................................................................................
III. Discussion .........................................................................................................................................................................................
A. The Commission’s Reliability Standards Proposal ..................................................................................................................
1. Applicability ........................................................................................................................................................................
2. Mandatory Reliability Standards ........................................................................................................................................
3. Availability of Reliability Standards ..................................................................................................................................
B. Applicability Issues ....................................................................................................................................................................
1. Definition of User of the Bulk-Power System ....................................................................................................................
2. Use of the NERC Functional Model ....................................................................................................................................
3. Applicability to Small Entities ............................................................................................................................................
4. Regional Reliability Organizations ......................................................................................................................................
5. Bulk-Power System v. Bulk Electric System ......................................................................................................................
C. Mandatory Reliability Standards ...............................................................................................................................................
1. Legal Standard for Approval of Reliability Standards ......................................................................................................
2. Commission Options When Acting on a Reliability Standard .........................................................................................
3. Prioritizing Modifications to Reliability Standards ...........................................................................................................
4. Trial Period ..........................................................................................................................................................................
5. International Coordination of Remands .............................................................................................................................
D. Common Issues Pertaining to Reliability Standards ................................................................................................................
1. Blackout Report Recommendations ....................................................................................................................................

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Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules

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2. Measures and Levels of Non-Compliance ..........................................................................................................................
3. Ambiguities and Potential Multiple Interpretations ..........................................................................................................
4. Technical Adequacy ............................................................................................................................................................
5. Fill-in-the-Blank Standards .................................................................................................................................................
E. Discussion of Each Individual Reliability Standard .................................................................................................................
1. BAL: Resource and Demand Balancing ..............................................................................................................................
2. CIP: Critical Infrastructure Protection ................................................................................................................................
3. COM: Communications .......................................................................................................................................................
4. EOP: Emergency Preparedness and Operations .................................................................................................................
5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities ...............................................................
6. INT: Interchange Scheduling and Coordination ................................................................................................................
7. IRO: Interconnection Reliability Operations and Coordination ........................................................................................
8. MOD: Modeling, Data, and Analysis ..................................................................................................................................
9. PER: Personnel Performance, Training and Qualifications ...............................................................................................
10. PRC: Protection and Control .............................................................................................................................................
11. TOP: Transmission Operations .........................................................................................................................................
12. TPL: Transmission Planning .............................................................................................................................................
13. VAR: Voltage and Reactive Control ..................................................................................................................................
14. Glossary of Terms Used in Reliability Standards ............................................................................................................
IV. Information Collection Statement ...................................................................................................................................................
V. Environmental Analysis ....................................................................................................................................................................
VI. Regulatory Flexibility Act Certification ..........................................................................................................................................
VII. Comment Procedures ......................................................................................................................................................................
VIII. Document Availability ...................................................................................................................................................................
Appendix
Appendix
Appendix
Appendix

A: Proposed Disposition of Standards, Glossary and Regional Differences
B: Commenters on Staff Preliminary Assessment
C: Abbreviations in this Document
D: High Priority List

I. Introduction

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1. Pursuant to section 215 of the
Federal Power Act (FPA), the
Commission is proposing to approve 83
of 107 proposed Reliability Standards,
including six of the eight regional
differences, and the Glossary of Terms
Used in Reliability Standards (glossary)
developed by the North American
Electric Reliability Council, on behalf of
its wholly-owned subsidiary, the North
American Electric Reliability
Corporation (NERC), which the
Commission has certified as the Electric
Reliability Organization (ERO)
responsible for developing and
enforcing mandatory Reliability
Standards. Those Reliability Standards
meet the requirements of section 215 of
the FPA and Part 39 of the
Commission’s regulations. However,
although we believe it is in the public
interest to make these Reliability
Standards mandatory and enforceable
by June 2007, we also find that much
work remains to be done. Specifically,
we believe that many of these Reliability
Standards require significant
improvement to address, among other
things, the recommendations of the
Blackout Report. We therefore propose,
pursuant to section 215(d)(5), to require
the ERO to make significant
improvements to many of the 83
Reliability Standards that are being
approved as mandatory and enforceable.
Appendix D provides a list of the

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Reliability Standards that should be
given the highest priority when the ERO
undertakes to make these
improvements. With respect to the
remaining 24 Reliability Standards, the
Commission proposes that they remain
pending at the Commission until further
information is provided. The
Commission is not proposing to remand
any Reliability Standards.
2. The Commission proposes to
amend the text of its regulations to
require that each Reliability Standard
identify the subset of users, owners, and
operators to which that particular
Reliability Standard applies. The
Commission also is proposing to amend
its regulations to require that each
Reliability Standard that is approved by
the Commission will be maintained in
the Commission’s Public Reference
Room and on the ERO’s Internet Web
site for public inspection.
3. On August 8, 2005, The Electricity
Modernization Act of 2005, which is
Title XII of the Energy Policy Act of
2005 (EPAct 2005), was enacted into
law.1 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. Once
approved, the Reliability Standards may
1 The Energy Policy Act of 2005, Pub. L. No. 109–
58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005),
to be codified at 16 U.S.C. 824o (2000).

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be enforced by the ERO, subject to
Commission oversight.
4. On February 3, 2006, the
Commission issued Order No. 672,
which implements section 215 of the
FPA and provides specific processes for
the certification of one entity as the
ERO, the development and approval of
mandatory Reliability Standards, and
the compliance with and enforcement of
approved Reliability Standards.2 On
April 4, 2006, NERC made two filings:
(1) An application for certification of
NERC Corporation as the ERO and (2) a
petition for Commission approval of 102
Reliability Standards, as well as eight
regional differences and a glossary of
terms.3 On July 20, 2006, the
Commission issued an order certifying
NERC Corporation as the ERO.4 This
rulemaking proceeding addresses
NERC’s submission of Reliability
Standards and represents the next
2 Rules 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).
3 The April 4, 2006 filing contained 102
Reliability Standards, a Glossary of Terms Used in
Reliability Standards and eight regional differences.
On August 28, 2006, NERC filed an additional 19
Reliability Standards and withdrew three of the 102
Reliability Standards. Eleven of the nineteen
reliability Standards replace those filed on April 4,
2006.
4 ERO Certification Order, 116 FERC ¶ 61,062.

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significant step toward achieving the
statutory goal of mandatory and
enforceable Reliability Standards.
5. The ERO’s filing is comprehensive,
and represents a significant effort by
NERC, the industry representatives who
serve on NERC’s standards development
teams, and the entities that participate
in NERC’s Reliability Standards
development process. After the August
2003 cascading blackout that affected
large portions of the central and eastern
United States and Canada, NERC
revised many of the then-existing NERC
operating policies and planning
standards to provide greater clarity and
compliance guidance. These revised
standards (referred to as ‘‘Version 0’’
and ‘‘Version 1’’) were developed using
NERC’s American National Standards
Institute (ANSI)-accredited Reliability
Standards development process and are
what has been filed with the
Commission for approval.
6. The Commission believes that these
Reliability Standards will form a solid
foundation on which to develop and
maintain the reliability of the North
American Bulk-Power System. At the
same time, the Commission recognizes,
as does NERC,5 that the Version 0 and
Version 1 standards were developed as
an initial step in the transition to clear,
enforceable Reliability Standards. As
such, some technical, enforceability and
policy aspects of the 107 proposed
Reliability Standards submitted by the
ERO can, and should, be improved.
7. Therefore, in evaluating NERC’s
proposal, the Commission recognizes
that the Reliability Standards are in a
state of transition and that NERC has
ongoing plans to improve them. Thus, at
this juncture, we will approve a
proposed Reliability Standard that
needs clarification, improvement, or
strengthening, provided that we are
confident that it satisfies the statutory
requirement that a Reliability Standard
must be ‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ 6 Rather than
remanding an imperfect Reliability
Standard, the NOPR generally proposes
to approve such a Reliability Standard.
In addition, as a distinct action under
the statute, the Commission proposes to
direct that the ERO modify such a
Reliability Standard, pursuant to section
215(d)(5) of the FPA, to address the
identified issues or concerns. This
approach would allow the proposed
Reliability Standard to be enforceable
while the ERO develops any required
modifications.
5 See
6 16

NERC Petition at 69.
U.S.C. 824o(d)(2).

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8. The Commission believes that, for
this period of transition from a
voluntary to a mandatory system of
compliance, the above course of action
is appropriate when reviewing the
ERO’s first set of proposed Reliability
Standards. This action provides the
benefit that mandatory and enforceable
Reliability Standards will be in effect
prior to the summer of 2007, the next
anticipated peak season for the nation’s
Bulk-Power System. Critical to our
decision to propose to approve such
Reliability Standards is NERC’s
representation to the Commission that
approval of the existing Reliability
Standards ‘‘will reinforce the
importance of these standards and will
have an immediate positive benefit with
regard to the reliability performance of
all bulk power system owners, operator
and users * * *.’’ 7
9. Accordingly, the Commission
proposes to approve the Reliability
Standards based on recognizing this
period of transition, the importance of
making them mandatory before the
summer of 2007, and by giving due
weight to the technical expertise of the
ERO with the expectation that the
Reliability Standards will accomplish
the purpose represented to the
Commission by the ERO; and that they
will improve the reliability of the BulkPower System by proactively preventing
situations that can lead to blackouts. By
taking this approach, we believe that the
responsibility for the technical
adequacy of the proposed Reliability
Standards falls squarely on the ERO,
and we expect the ERO to monitor the
effectiveness of the proposed Reliability
Standards and inform us if any
Reliability Standard proves, in practice,
to be inadequate in protecting and
improving Bulk-Power System
reliability.
10. Further, the Commission proposes
to request additional information with
regard to 24 proposed Reliability
Standards. These proposed Reliability
Standards would not be approved or
remanded by the Commission until
further action is taken by the ERO. This
group of Reliability Standards includes
NERC’s so-called ‘‘fill-in-the-blank’’
standards that require regional
reliability organizations to develop—
and users, owners, or operators to
comply with—regional criteria.8 Until
the Commission receives this
supplemental information to fill in the
‘‘blanks’’ 9 and assurances that the
7 NERC

Petition at 25.
id. at 87–90.
9 The ERO is reminded when filling in these
blanks that a regional difference is generally
permitted when it is more stringent or when there
8 See

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processes to fill in the blanks satisfy our
procedural requirements, the
Commission is not in a position to
approve or remand such Reliability
Standards. Second, a proposed
Reliability Standard that would apply
only to regional reliability organizations
will not be approved or remanded until
the ERO identifies a user, owner or
operator of the Bulk-Power System as
the applicable entity.10
11. Although the proposed Reliability
Standards for which the Commission is
requesting additional information will
not be enforceable under section 215,
this does not mean that no standards
governing a particular matter are in
place. Rather, in the interim, though not
enforceable under section 215,
compliance with these Reliability
Standards would be expected as a
matter of good utility practice.
II. Background
A. Voluntary Reliability Standards
12. In the aftermath of the 1965
blackout in the northeast United States,
the electric utility industry established
NERC, a voluntary reliability
organization. Since its inception, NERC
has developed Operating Policies and
Planning Standards that provide
voluntary guidelines for operating and
planning the North American BulkPower System.
13. A common cause of the past three
major regional blackouts was violation
of NERC’s then existing Operating
Policies and Planning Standards. During
July and August 1996, the west coast of
the United States experienced two
cascading blackouts caused by
violations of voluntary Operating
Policies.11 In response to the outages,
the Secretary of Energy convened a task
force to advise the U.S. Department of
is a geographical/physical reason for the difference.
Consolidation of regional standards into a single
continent-wide standard should not result in a
lowest common denominator. Order No. 672 at P
291.
10 In addition, some of the proposed Reliability
Standards overlap with other Commission
regulatory initiatives. For example, in a recent
Notice of Proposed Rulemaking, the Commission
has proposed to direct public utilities, in
conjunction with NERC and the North American
Energy Standards Board to provide for greater
consistency in Available Transmission Capacity
(ATC) calculation. See Preventing Undue
Discrimination and Preference in Transmission
Service, 71 FR 32636 (June 6, 2006), 71 FR 39251
(July 12, 2006), FERC Stats. & Regs. ¶ 39,602 (May
19, 2006) (OATT Reform NOPR).
11 The Electric Power Outages in the Western
United States, July 2–3, 1996, at 76 (ftp://
www.nerc.com/pub/sys/all_updl/docs/pubs/
doerept.pdf) and WSCC Disturbance Report, for the
Power System Outage that Occurred on the Western
Interconnection August 10, 1996, at 4 (ftp://
www.nerc.com/pub/sys/all_updl/docs/pubs/
AUG10FIN.pdf).

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Energy (DOE) on issues needed to be
addressed to maintain the reliability of
the Bulk-Power System. In a September
1998 report, the task force
recommended, among other things, that
federal legislation should grant more
explicit authority for the Commission to
approve and oversee an organization
having responsibility for bulk-power
reliability standards.12 Further, the task
force recommended that such legislation
provide for Commission jurisdiction
over reliability of the Bulk-Power
System and Commission
implementation of mandatory,
enforceable reliability standards.
14. On August 14, 2003, a blackout
affected significant portions of the
Midwest and Northeast United States,
and Ontario, Canada. This blackout
affected an estimated 50 million people
and 61,800 megawatts of electric load. A
joint U.S.-Canada task force studied the
causes of the August 14, 2003 blackout
and determined that several entities
violated NERC’s then-effective
Operating Policies and Planning
Standards, and that several of the
standards contained ambiguities that
rendered the standards ineffective.
Those violations and ambiguities
directly contributed to the blackout.13
The joint task force, in its
recommendations to prevent or
minimize the scope of future blackouts,
identified the need for legislation to
make reliability standards mandatory
and enforceable, with penalties for noncompliance and identified specific
ambiguities within the standards that
should be corrected to make the
standards effective.14

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B. EPAct 2005 and Order No. 672
15. EPAct 2005 adds a new section
215 to the FPA, which provides for a
system of mandatory and enforceable
Reliability Standards. On February 3,
2006, the Commission issued Order No.
672, implementing section 215 of the
FPA.15 Pursuant to Order No. 672, the
Commission certified one organization,
12 Maintaining Reliability in a Competitive U.S.
Electricity Industry, Final Report of the Task Force
on Electric System Reliability, Secretary of Energy
Advisory Board, U.S. Department of Energy
(September 1998), at 25–27, 65–67.
13 The joint team, known as the U.S.-Canada
Power System Outage Task Force, issued a Final
Report on the August 14, 2003 Blackout in the
United States and Canada: Causes and
Recommendations (Blackout Report) on April 5,
2004, which presented an in-depth analysis of the
causes of the blackout and recommendations for
avoiding future blackouts.
14 See id. at 140–42.
15 Order No. 672, 71 FR 8662 (Feb. 17, 2006),
FERC Stats. & Regs. ¶ 31,204 (2006), order on reh’g,
Order No. 672–A, 71 FR 19814 (Apr. 18, 2006),
FERC Stats. & Regs. ¶ 31,212 (2006). Terms defined
in Order No. 672 are capitalized in this order.

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NERC, as the ERO. The ERO is required
to develop Reliability Standards, which
are subject to Commission review and
approval.16 Once approved, the
Reliability Standards may be enforced
by the ERO, subject to Commission
oversight.17 The Reliability Standards
will apply to users, owners and
operators of the Bulk-Power System.
The ERO must submit each proposed
Reliability Standard to the Commission
for approval.
16. Section 215(d)(2) of the FPA and
the Commission’s regulations provide
that the Commission may approve a
proposed Reliability Standard if it
determines that the proposal is just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest. The Commission specified in
Order No. 672 certain general factors it
would consider when assessing whether
a particular Reliability Standard is just
and reasonable.18 According to this
guidance, a proposed Reliability
Standard must provide for the Reliable
Operation of Bulk-Power System
facilities and may impose a requirement
on any user, owner, or operator of such
facilities. It must be designed to achieve
a specified reliability goal and must
contain a technically sound means to
achieve this goal. The proposed
Reliability Standard should be clear and
unambiguous regarding what is required
and who is required to comply. The
possible consequences for violating a
proposed Reliability Standard should be
clear and understandable to those who
must comply. There should be a clear
criterion or measure of whether an
entity is in compliance with a proposed
Reliability Standard. While a proposed
Reliability Standard does not
necessarily need to reflect the optimal
method for achieving its reliability goal,
16 Section 215(a)(3) of the FPA defines the term
Reliability Standard to mean ‘‘a requirement,
approved by the Commission under this section, to
provide for reliable operation of the bulk-power
system. This term includes requirements for the
operation of existing bulk-power system facilities,
including cybersecurity protection, and the design
of planned additions or modifications to such
facilities to the extent necessary to provide for the
reliable operation of the bulk-power system, but the
term does not include any requirement to enlarge
such facilities or to construct new transmission
capacity or generation capacity.’’ 16 U.S.C.
824o(a)(3).
Section 215(a)(4) of the FPA defines the term
‘‘reliable operation’’ broadly to mean, ‘‘* * *
operating the elements of the bulk-power system
within equipment and electric system thermal,
voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of
such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or
unanticipated failure of system elements.’’ 16
U.S.C. 824o(a)(4).
17 The Commission can independently enforce
Reliability Standards. 16 U.S.C. 824o(e)(3).
18 Order No. 672 at P 262, 321–337.

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a proposed Reliability Standard should
achieve its reliability goal effectively
and efficiently. A proposed Reliability
Standard must do more than simply
reflect stakeholder agreement or
consensus around the ‘‘lowest common
denominator.’’ It is important that the
Reliability Standards developed through
any consensus process be sufficient to
adequately protect Bulk-Power System
reliability.19
17. A proposed Reliability Standard
may take into account the size of the
entity that must comply and the costs of
implementation. However, the ERO
should not propose standards that
would achieve less than operational
excellence or otherwise be inadequate to
support Bulk-Power System reliability.
A proposed Reliability Standard should
be a single standard that applies across
the North American Bulk-Power System
to the maximum extent this is
achievable taking into account
geographic variations in grid
characteristics, terrain, weather, and
other factors. It should also account for
regional variations in the organizational
and corporate structures of transmission
owners and operators, variations in
generation fuel type and ownership
patterns, and regional variations in
market design if these affect the
proposed Reliability Standard. Finally, a
proposed Reliability Standard should
have no undue negative effect on
competition.20 Order No. 672 directs the
ERO to explain how the proposal
satisfies the factors the Commission
identified and how the ERO balances
any conflicting factors when seeking
approval of a proposed Reliability
Standard.21
18. Pursuant to section 215(d)(2) of
the FPA and section 39.5(c) of the
Commission’s regulations, the
Commission is required to give due
weight to the technical expertise of the
ERO with respect to the content of a
Reliability Standard or to a Regional
Entity organized on an Interconnectionwide basis with respect to a proposed
Reliability Standard or a proposed
modification to a Reliability Standard to
be applicable within that
Interconnection. However, the
Commission is not required to defer to
the ERO or a Regional Entity with
respect to the effect of a proposed
Reliability Standard or proposed
modification to a Reliability Standard
on competition.22
19. The Commission’s regulations
require the ERO to file with the
19 Order

No. 672 at P 329.
No. 672 at P 332.
21 Id. at P 337.
22 18 CFR 39.5(c)(1), (3).
20 Order

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Commission each new or modified
Reliability Standard that it proposes to
be made effective under section 215 of
the FPA. The filing must include a
concise statement of the basis and
purpose of the proposed Reliability
Standard, a summary of the Reliability
Standard development proceedings
conducted by either the ERO or
Regional Entity, together with a
summary of the ERO’s Reliability
Standard review proceedings, and a
demonstration that the proposed
Reliability Standard is just, reasonable,
not unduly discriminatory or
preferential, and in the public interest.23
20. The Commission will remand to
the ERO for further consideration a
proposed new or modified Reliability
Standard that the Commission
disapproves in whole or in part.24 When
remanding a Reliability Standard to the
ERO, the Commission may order a
deadline by which the ERO must submit
a proposed or modified Reliability
Standard.

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C. The Electric Reliability Organization
21. NERC is a New Jersey nonprofit
corporation with a membership
comprised of the eight regional
reliability councils covering the
contiguous 48 States, several provinces
in Canada and a portion of Baja
California Norte, Mexico. NERC has
operated as a voluntary, industrysponsored reliability organization
formed to ensure the reliability of the
North American Bulk-Power System.
22. NERC filed an application with
the Commission on April, 4, 2006
seeking certification as the ERO. NERC
stated that it expects NERC Council and
NERC Corp. to merge upon being
certified as the ERO by the Commission.
NERC Corp. will be the surviving entity
and will assume the assets and
liabilities of NERC Council.
23. In its July 20, 2006 order certifying
NERC as the ERO, the Commission
directed NERC to submit a compliance
filing incorporating various
clarifications and revisions to its bylaws
and rules of procedure. Among the
improvements the Commission has
directed NERC to undertake as the ERO
are changes to expedite the existing
process for developing new Reliability
Standards in response to a Commission
deadline to deal with an urgent
situation. The order also directs NERC
to modify its proposed pro forma
delegation agreement for delegating
23 18
24 18

CFR 39.5(a).
CFR 39.5(e).

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enforcement authority to a Regional
Entity.25
D. NERC Petition for Approval of
Reliability Standards
24. On April 4, 2006, as modified on
August 28, 2006 NERC submitted to the
Commission a petition seeking approval
of the 107 proposed Reliability
Standards that are the subject of this
NOPR (NERC Petition).26 NERC states
that 90 of these Reliability Standards,
known as ‘‘Version 0’’ standards,
became effective on a voluntary basis on
April 1, 2005. It explains that the
Version 0 standards ‘‘are a translation,
with certain improvements, of NERC’s
operating policies that were developed
over several decades and its planning
standards, which were approved in
September 1997.’’ 27 In addition, the
April 4, 2006 filing includes 12 new
Reliability Standards that were
approved by the NERC board of trustees
for implementation in February 2006.
According to NERC, the 107 proposed
Reliability Standards collectively define
overall acceptable performance with
regard to operation, planning and design
of the North American Bulk-Power
System. Seven of these Reliability
Standards specifically incorporate one
or more ‘‘regional differences’’ (which
can include an exemption from a
Reliability Standard) for a particular
region or subregion, resulting in eight
regional differences. NERC requests that
the Reliability Standards become
effective on January 1, 2007, or an
alternative date determined by the
Commission. NERC also states that it
simultaneously filed the proposed
Reliability Standards with governmental
authorities in Canada.
25. Each proposed Reliability
Standard follows a common format that
includes five organizational elements:
a. Introduction
1. Title: a phrase that describes the
topic of the Reliability Standard.
2. Number: A unique identification
number that starts with three letters to
identify the group followed by a dash
and a three digit number, followed by a
25 Although the ERO Certification Order directs
NERC to modify the pro forma delegation
agreement, the pro forma agreement will not be refiled with the Commission before negotiating the
individual delegation agreements. The pro forma
agreement will form the basis for the individual
Regional Entity delegation agreements that will be
filed with the Commission. ERO Certification
Order, 116 FERC ¶ 61,062 at P 518.
26 The filed proposed Reliability Standards are
not attached to this NOPR but are available on the
Commission’s eLibrary document retrieval system
in Docket No. RM06–16–000 and are available on
the ERO’s Web site, http://www.nerc.com/∼filez/
nerc_filings_ferc.html.
27 See NERC Petition at 28.

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dash and the version number e.g., PRC–
014–0.
3. Purpose: One or more sentences
that explicitly states the outcome to be
achieved by the adoption of the
Reliability Standard.
4. Applicability:
4.1 Each entity, as defined by the
NERC Functional Model, that must
comply with the Reliability Standard,
such as Transmission Owner.
b. Requirements
R1. A listing of explicitly stated
technical, performance and
preparedness requirements and who is
responsible for achieving them.
c. Measures
M1. A listing of the factors and the
process NERC will use to assess
performance and outcomes in order to
determine non-compliance, and who is
responsible for achieving the measures.
Measures are ‘‘the evidence that must be
presented to show compliance’’ with a
standard and ‘‘are not intended to
contain the quantitative metrics for
determining satisfactory
performance.’’ 28
d. Compliance
1. Compliance Monitoring Process
1.1 Compliance Monitoring
Responsibility: NERC’s explanation of
who is responsible for assessing
performance or outcomes.
1.2 Compliance Monitoring Period
and Reset Timeframe: The timeframe for
each compliance monitoring period
before it is reset for the next period.
1.3 Data Retention: How long
compliance documentation needs to
remain on file.
1.4 Additional Compliance
Information: Any other information
relating to compliance.
2. Levels of Non-Compliance: Usually
four levels of non-compliance are
identified, with level 1 being used for
the least severe non-compliance and
level 4 for the most severe noncompliance.
e. Regional Differences
Identification of any regional
differences that have been approved by
the applicable NERC Committee
(including Regions that are exempt).
Version History: The chronological
history of changes to the standard.
26. In its April 4, 2006 petition, NERC
requested ‘‘unconditional’’ approval of
77 proposed Reliability Standards and
the glossary of terms. Further, NERC
28 NERC Comments at 104. NERC clarified its
position that Measures did not include metrics after
the Staff Preliminary Assessment interpreted the
Measures section as including metrics.

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requested ‘‘conditional’’ approval of 25
proposed Reliability Standards.
27. In a June 26 filing, NERC revised
its recommended action on the
proposed Reliability Standards: (1)
Unconditional approval of 51 proposed
Reliability Standards, to become
enforceable in the U.S. on a date in 2007
to be determined by the Commission; (2)
conditional approval of 26 proposed
‘fill-in-the-blank’ Reliability Standards,
to become enforceable in the U.S. on a
date in 2007 to be determined by the
Commission. NERC recommends that
‘‘conditional approval’’ shall mean ‘‘that
any limitation of the standard caused by
the presence of a regional ‘fill-in-theblank’ requirement * * * would be
considered as a factor in the evaluation
of circumstances surrounding an alleged
violation of the standard and the
determination of a violation and setting
of an appropriate penalty;’’ and (3)
conditional approval of another 25
proposed Reliability Standards lacking
Measures or Levels of Non-Compliance,
to become enforceable in the U.S. on a
date in 2007 to be determined by the
Commission. In addition, NERC plans to
file modified Reliability Standards in
early November 2006 that will add
missing Measures and Levels of Noncompliance elements as well as risk
factors. NERC recommends that the
Commission act on the proposed
modifications to Reliability Standards
that are currently before the
Commission in the same proceeding to
achieve an initial set of Reliability
Standards.
28. On August 28, 2006, NERC
submitted 27 new and revised
standards. The Commission will address
these proposed new and revised
Reliability Standards in this rulemaking
proceeding, except for eight proposed
Reliability Standards that relate to cyber
security. Reliability Standards CIP–002
through CIP–009 will be addressed in a
separate rulemaking proceeding in
Docket No. RM06–22–000.
E. Staff Preliminary Assessment
29. On May 11, 2006, Commission
staff issued a ‘‘Staff Preliminary
Assessment of the North American
Electric Reliability Council’s Proposed
Mandatory Reliability Standards’’ (Staff
Preliminary Assessment). The Staff
Preliminary Assessment identified
staff’s preliminary observations and
concerns regarding NERC’s then-current
voluntary reliability standards. The Staff
Preliminary Assessment describes
issues common to a number of proposed
Reliability Standards. It reviewed and
identified issues regarding each
individual Reliability Standard but did
not make specific recommendations

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regarding the appropriate action on a
particular proposal.
30. The Staff Preliminary Assessment
provided a basis for soliciting input
regarding which of the proposed
Reliability Standards should be
approved, approved on an interim basis,
or remanded to the ERO; established a
platform from which to identify and
prioritize potential problems with the
proposed Reliability Standards; and
provided a comprehensive and objective
assessment of NERC’s then-current 102
Reliability Standards.
31. Comments on the Staff
Preliminary Assessment were due by
June 26, 2006. Entities that filed
comments are listed in Appendix A to
this NOPR. Approximately 50 persons
filed comments in response to the Staff
Preliminary Assessment. In addition, on
July 6, 2006, the Commission held a
technical conference to discuss NERC’s
proposed Reliability Standards, the Staff
Preliminary Assessment and other
related issues. The technical conference
was transcribed, and is a part of the
record in this docket.
32. The written comments as well as
the panel discussions at the technical
conference have been very informative,
and reference to the public comments is
mentioned throughout the NOPR.
Moreover, our proposed disposition of
the Reliability Standards reflects our
consideration of all comments that were
submitted.
III. Discussion
A. The Commission’s Reliability
Standards Proposal
33. The Commission’s proposed
reliability regulation is entitled
Mandatory Reliability Standards for the
Bulk-Power System. Section 215(b) of
the FPA obligates all users, owners and
operators of the Bulk-Power System to
comply with Reliability Standards that
become effective pursuant to the
processes set forth in the statute and in
Part 39 of the Commission’s regulations.
The complete text of the proposed rule
is provided in the Attachment to this
notice of proposed rulemaking.
34. The proposed regulation is
organized into three sections:
40.1—Applicability;
40.2—Mandatory Reliability
Standards; and
40.3—Availability of Reliability
Standards.
1. Applicability
35. Section 40.1(a) of the proposed
regulations provides that this Part
applies to all users, owners and
operators of the Bulk-Power System
within the United States (other than

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Alaska and Hawaii) including, but not
limited to, the entities described in
section 201(f) of the FPA. This
statement is consistent with § 215(b) of
the FPA and section 39.2 of the
Commission’s regulations.
36. Section 40.1(b) requires each
Reliability Standard made effective
under this Part to identify the subset of
users, owners and operators to whom
that particular Reliability Standard
applies.
2. Mandatory Reliability Standards
37. Section 40.2 (a) of the proposed
regulations requires that each applicable
user, owner or operator of the BulkPower System comply with
Commission-approved Reliability
Standards developed by the ERO, and
provides that the Commission-approved
Reliability Standards can be obtained
from the Commission’s Public Reference
Room at 888 First Street, NE., Room 2A,
Washington, DC 20426.
38. Section 40.2(b) of the proposed
regulations provides that a proposed
modification to a Reliability Standard
proposed to become effective pursuant
to § 39.5 shall not be effective until
approved by the Commission.
3. Availability of Reliability Standards
39. Section 40.3 of the proposed
regulations would require that the ERO
maintain in electronic format that is
accessible from the Internet the
complete set of effective Reliability
Standards that have been developed by
the ERO and approved by the
Commission. The Commission believes
that ready access to an electronic
version of the effective Reliability
Standards will enhance transparency
and help avoid confusion as to which
Reliability Standards are mandatory and
enforceable. We note that NERC
currently maintains the existing,
voluntary reliability standards on the
NERC Web site.
40. While the NOPR discusses each
proposed Reliability Standard and
identifies the Commission’s proposed
disposition for each Reliability
Standard, neither the text nor the title
of an approved Reliability Standard
would be codified in the Commission’s
regulations. Rather, as indicated above,
each applicable user, owner or operator
of the Bulk-Power System would be
required to comply with Commissionapproved Reliability Standards that are
available in the Commission’s Public
Reference Room and on the Internet at
the ERO’s Web site.
41. This approach would preserve the
statutory options of approving a
proposed Reliability Standard or
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‘‘by rule or order.’’ 29 While we
anticipate that the Commission would
address through the rulemaking process
most, if not all, new Reliability
Standards proposed by NERC, certain
modifications may be appropriately
addressed by order.
B. Applicability Issues
1. Definition of User of the Bulk-Power
System
42. In Order No. 672, the Commission
acknowledged that, generally, a person
directly connected to the Bulk-Power
System selling, purchasing or
transmitting electric energy over the
Bulk-Power System is a ‘‘User of the
Bulk-Power System.’’ However, the
Commission declined to adopt a formal
definition, explaining that, ‘‘until we
have proposed Reliability Standards
before us, we will reserve further
judgment on whether a definition of
‘User of the Bulk-Power System’ is
appropriate or whether the decision of
who is a ‘User of the Bulk-Power
System’ should be made on a case-bycase basis.’’ 30
43. We do not propose a generic
definition of the term ‘‘User of the BulkPower System.’’ Rather, the Commission
will determine applicability on a
standard-by-standard basis.31 The
phrase ‘‘user, owner or operator of the
Bulk-Power System’’ as used in section
215(b) of the FPA indicates the scope of
the Commission’s authority with regard
to compliance with Reliability
Standards. The proposed regulations
would require that the ERO identify in
each proposed Reliability Standard the
specific subset of users, owners and
operators of the Bulk-Power System to
which the proposed Reliability Standard
would apply. In fact, this is NERC’s
current practice, and each of the 107
proposed Reliability Standards
submitted by NERC includes an
‘‘applicability’’ provision that identifies
the specific categories of applicable
entities based on NERC’s Functional
Model.32 Parties concerned that a
29 See

16 U.S.C. 824o(d)(2).
No. 672 at P 99.
31 Many of the proposed Reliability Standards
apply to reliability coordinators and balancing
authorities and other clearly appropriate entities.
We believe that such Reliability Standards do not
raise applicability issues. Thus, in our standard-bystandard analysis, the Commission’s silence as to
applicability issues means that it agrees with the
ERO’s proposed applicability of a Reliability
Standard.
32 See NERC Petition at 80–81. For information
regarding the Functional Model, see NERC
Reliability Functional Model, Function Definitions
and Responsibility Entities, Version 2, February 10,
2004. NERC is currently developing revisions to the
Functional Model (referred to as ‘‘Version 3’’) that,
among other things, changes the name of the

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proposed Reliability Standard would
apply more broadly than the statute
allows may raise their concern in the
context of the specific Reliability
Standard. We believe that this approach
provides sufficient notice regarding
which entities are ‘‘users of the BulkPower System’’ that must comply with
a specific Reliability Standard.
2. Use of the NERC Functional Model
44. As mentioned above, each
Reliability Standard proposed by the
ERO identifies entities to which the
Reliability Standard applies based on
the NERC Functional Model.33 The Staff
Preliminary Assessment observed that
the Functional Model omits the
categories of ‘‘users, owners and
operators,’’ and includes other
categories of entities that are not users,
owners or operators of the Bulk-Power
System.34
45. NERC states that, while the term
‘‘users, owners and operators’’ defines
the statutory applicability of the
Reliability Standards, the Functional
Model adds descriptive detail to
reliability functions so the applicability
of each Reliability Standard can be
clearly defined. NERC explains that
‘‘every entity class described in the
Reliability Functional Model performs
functions that are essential to the
reliability of the bulk power system.’’ 35
Several commenters concur with NERC
and suggest that the Commission
approve the Functional Model so that
future modifications would require
Commission approval. MISO and
Allegheny point to specific examples of
what they consider ambiguities in the
NERC Functional Model, primarily in
the context of applicability to RTO or
ISO functions.
46. The objective here is to make sure
that each Reliability Standard is
sufficiently clear with respect to
applicability and specifically identifies
each category of entities to which it
applies. The NERC Functional Model
reliability authority to ‘‘reliability coordinator’’ and
explains its role in ‘‘wide area’’ reliability oversight.
Both versions of the Functional Model are available
on NERC’s Web site at: http://www.nerc.com/∼filez/
functionalmodel.html.
33 The functional categories include: (1)
Reliability coordinator, (2) balancing authority, (3)
planning authority, (4) transmission planner, (5)
transmission operator, (6) transmission service
provider, (7) transmission owner, (8) resource
planner, (9) distribution provider, (10) generator
owner, (11) generator operator, (12) load-serving
entity, (13) purchasing-selling entity, (14)
compliance monitor. ERO Certification Order, 116
FERC ¶ 61,062, at n.247.
34 Staff Preliminary Assessment at 24.
35 NERC Comments at 96. In addition to its April
4, 2006, Petition, NERC filed comments in response
to the Staff Preliminary Assessment on June 26,
2006 (NERC Comments).

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represents a reasonable and practical
approach to determining the
applicability of a particular Reliability
Standard. This approach is consistent
with the ERO Certification Order, in
which the Commission, in the context of
addressing NERC’s proposed
compliance registry, found that ‘‘NERC’s
functional approach provides a
reasonable means to ensure that the
proper entities are registered and that
each knows which Commissionapproved Reliability Standard(s) are
applicable to it.’’ 36 Thus, we agree with
NERC that identifying specific
functional categories of entities that
comprise users, owners and operators of
the Bulk-Power System provides a
useful level of detail and appears to be
more practical than simply identifying
an applicable entity as a user, owner or
operator. Accordingly, we propose to
use the NERC functional model to
identify the applicable entities to which
each Reliability Standard applies.
47. We are mindful of the concerns of
certain commenters that the Functional
Model may contain ambiguities and add
or omit certain entities or functions.
Elsewhere in the NOPR we are
proposing to require NERC to
specifically address these concerns.37
Further we note that NERC’s Rules of
Procedure pertaining to the NERC
compliance registry provide that NERC
will notify an entity before it is formally
registered and allow an opportunity for
an entity to challenge its inclusion on
the compliance registry.38 This process
should resolve any specific disputes
that may arise.
48. Some commenters suggest that
any future modification to the
Functional Model could affect the
categories of entities that must comply
with a particular Reliability Standard,
without the benefit of the open,
stakeholder process required when the
ERO develops a modification to a
Reliability Standard. Because the
Functional Model is so closely linked
with applicability of the Reliability
Standards, the Commission proposes to
require the ERO to submit any future
modifications to the Functional Model
that may affect the applicability of the
Reliability Standards for Commission
approval.
3. Applicability to Small Entities
49. NERC indicates that a Reliability
Standard may identify limitations on
36 ERO Certification Order, 116 FERC ¶ 61,062, at
P 689.
37 For example, commenters’ concerns regarding
applicability to ISOs and RTOs are discussed in
detail in the chapter on proposed communications
Reliability Standards.
38 See NERC Rule of Procedure section 501.1.3.

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applicability based on electric facility
characteristics ‘‘such as generators with
a nameplate rating of 20 MW or greater,
or transmission facilities energized at
200 kV or greater.’’ 39 It explains that,
‘‘to ensure that the standards are
applied in a cost effective manner and
the applicability of the standards is
focused on entities having a material
impact on reliability of the bulk power
system, it is necessary in the future to
begin providing greater specificity in the
applicability section of the
standards.’’ 40 NERC, as the ERO,
indicates that it plans to develop a set
of guidelines on such limitations for the
standard drafting teams and to require
that a new Reliability Standard or a
modification to an existing Reliability
Standard, going forward, include this
degree of specificity.
50. A number of commenters advocate
that a mandatory Reliability Standard
should not apply to entities that have no
‘‘material impact’’ on the Bulk-Power
System.41 These commenters also ask
that the Commission encourage and
facilitate contractual arrangements for
the delegation of compliance obligations
faced by small entities to Joint Action
Agencies (JAAs) and other organizations
that have ongoing relationships with
NERC.
51. While NERC has yet to submit a
specific proposal, the Commission
agrees that it is important to examine
the impact a particular entity may have
on the Bulk-Power System in
determining the applicability of a
specific Reliability Standard. However,
we do not believe that a ‘‘blanket
waiver’’ approach that would exempt
entities below a threshold level from
compliance with all Reliability
Standards would be appropriate because
there may be instances where a small
entity’s compliance is critical to
reliability. For instance, the reporting of
a sabotage event required by CIP–001–
0 may be important regardless of the
size of the entity since such reporting
helps others by putting them on notice
of potential attacks to their own
systems. For purposes of assessing
compliance with a particular Reliability
Standard, it may be appropriate to
differentiate among certain subsets of
users, owners, and operators. For
example, the requirement to have
adequate communications capabilities
to address real-time emergency
conditions (COM–001–0 and COM–
002–1) may be necessary for all
applicable entities regardless of size or
role, although we understand that the
39 NERC

Petition at 9.
40 Id. at 82.
41 See, e.g., Alcoa, APPA, BPA and TAPS.

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implementation of these requirements
for applicable entities may vary based
on size or role.42 Therefore, we propose
to direct NERC to take such factors into
account in determining applicability, as
well as compliance requirements, for a
particular Reliability Standard.
52. In addition, the Commission
solicits comment on whether, despite
the existence of a threshold in a
particular standard (e.g., generators with
a nameplate rating of 20 MW or over),
the ERO or a Regional Entity should be
permitted to include an otherwise
exempt facility, e.g., a 15 MW generator,
on a facility-by-facility basis, if it
determines that the facility is needed for
Bulk-Power System reliability. If so,
what if any process should the ERO or
Regional Entity provide when making
such a determination?
53. NERC has proposed registration of
joint action agencies or similar
organizations that would register on
behalf of their members. APPA asks that
NERC permit a joint action agency or
similar organization to accept
compliance responsibilities on a
standard-by-standard basis. We propose
to direct NERC to develop procedures
which permit a joint action agency or
similar organization to accept
compliance responsibility on behalf of
their members.
4. Regional Reliability Organizations
54. NERC has proposed 28 Reliability
Standards that would apply, in whole or
in part, to a regional reliability
organization.43 Many of the 28
Reliability Standards concern such
matters as data gathering, data base
maintenance, preparation of
assessments and other ‘‘process’’ related
responsibilities. Others are what have
been referred to as ‘‘fill-in-the-blank’’
Reliability Standards. Many of the
proposed Reliability Standards that
have compliance measures refer to the
regional reliability organization as a
compliance monitor.
42 For example, a dedicated phone line that
would remain operative during a power failure may
suffice for a small cooperative with minimal BulkPower System facilities, while a large investorowned utility may need a sophisticated
communication system with redundancy and
diverse routing requirements.
43 NERC states that the regional reliability
organizations are the same as the existing eight
regional reliability councils and that ‘‘a regional
reliability organization may or may not be the same
organization that is providing statutory functions
delegated by agreement with a regional entity.’’
NERC Comments at 101. In the order certifying
NERC as the ERO, the Commission asked that NERC
provide additional information regarding the
possible ongoing role of the regional reliability
organizations and their relationship with Regional
Entities. ERO Certification Order, 116 FERC
¶ 61,062, at P 76.

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55. The Staff Preliminary Assessment
expressed concern as to whether a
Reliability Standard that applies to a
regional reliability organization is
enforceable pursuant to section 215(e) of
the FPA, since it is not clear whether a
regional reliability organization is a
user, owner or operator of the BulkPower System. NERC contends that
such Reliability Standards are
enforceable, and identifies several legal
theories to support its position.
Specifically, NERC contends that such
Reliability Standards are enforceable
because: (1) Each regional reliability
organization will voluntarily register as
a member of NERC and thereby be
bound to comply; 44 (2) a regional
reliability organization performs
functions on behalf of its members that
are users, owners and operators of the
Bulk-Power System; and (3) NERC is in
the process of updating its functional
model to provide a functional
description of a regional reliability
organization that includes functions that
NERC believes are consistent with a
system operator. EEI and other
commenters question whether a
Reliability Standard can be enforced
against a regional reliability
organization.
56. The Commission is not persuaded
that a regional reliability organization’s
compliance with a Reliability Standard
can be enforced as proposed by NERC.
Section 215 of the FPA does not appear
to recognize a regional reliability
organization as a user, owner or
operator of the Bulk-Power System.
Moreover, NERC’s arguments assume
that each regional reliability
organization will voluntarily join as a
member of NERC and be legally bound
as a member to comply. Further, NERC’s
claim that a regional reliability
organization will perform functions on
behalf of its members that are users,
owners and operators of the Bulk-Power
System does not establish a binding
agency relationship that would create a
legal basis for requiring regional
reliability organization compliance with
Reliability Standards. While it is
important that the existing regional
reliability organizations continue to
fulfill their current roles during the
transition to a regime where Reliability
Standards are mandatory and
enforceable, we do not understand why,
once the transition is complete, a
regional reliability organization should
play a role separate from a Regional
Entity whose function and
44 Pursuant to NERC’s ERO application, a member
‘‘accepts the responsibility to promote, support, and
comply with the Bylaws, Rules of Procedure, and
Reliability Standards * * *.’’

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responsibility is explicitly recognized
by section 215 of the FPA. We seek
comment on whether there is any need
to maintain separate roles for regional
reliability organizations with regard to
establishing and enforcing Reliability
Standards under section 215.
57. At present, 28 of the proposed
Reliability Standards are written to
apply solely or partially to regional
reliability organizations.45 We do not
believe it is necessary or useful to
remand those Reliability Standards
simply because they refer to the regional
reliability organization. For the five
standards that apply partially to
regional reliability organizations, the
Commission proposes action similar to
other Reliability Standards that need
improvement, i.e., to approve them and
direct modification.46 For the other
Reliability Standards, as an interim
measure, we propose to direct the ERO
to use its authority pursuant to § 39.2(d)
of our regulations to require users,
owners, and operators to provide to the
regional reliability organizations the
information 47 related to data gathering,
data maintenance, reliability
assessments and other ‘‘process’’-type
functions.48 We believe that this
approach is necessary to ensure that
there will be no ‘‘gap’’ during the
transition from the current voluntary
reliability model to a mandatory system
in which Reliability Standards are
enforced by the ERO and Regional
Entities. In the long run, we propose to
make the Regional Entities responsible,
through delegation by the ERO, for the
functions currently performed by the
regional reliability organizations. As
part of this change, the delegation
agreements to the Regional Entities
should be modified to bind the Regional
Entities to assume these duties and
responsibility for noncompliance. In
addition, the Reliability Standards
should be modified to apply through the
Functional Model, to the users, owners
and operators of the Bulk-Power System
that are responsible for providing
information.
58. Further, the Commission proposes
to require that any Reliability Standard
45 BAL–002, EOP–004, EOP–007, FAC–003, IRO–
001, MOD–001, MOD–002, MOD–003, MOD–004,
MOD–005, MOD–008, MOD–009, MOD–011, MOD–
013, MOD–014, MOD–015, MOD–016, MOD–024,
MOD–025, PRC–002, PRC–003, PRC–006, PRC–012,
PRC–013, PRC–014, PRC–020, TPL–005, and TPL–
006.
46 BAL–002, EOP–004, FAC–003, IRO–001, and
MOD–016. Three of these (EOP–004, FAC–003 and
MOD–016) are ‘‘data-gathering’’ or ‘‘process-type’’
Reliability Standards.
47 EOP–007, MOD–011, MOD–013, MOD–014,
MOD–015, MOD–024, MOD–025, PRC–002, PRC–
003, PRC–006, PRC–012, PRC–013, PRC–014, PRC–
020, TPL–005, and TPL–006.
48 18 CFR 39.2(d).

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that references a regional reliability
organization as a compliance monitor be
modified to refer to the ERO as the
compliance monitor.
59. Finally, for the remaining seven
Reliability Standards (fill-in-the-blank
standards),49 we propose to request
additional information on these
proposed Reliability Standards pending
receipt of additional information, as
detailed below in the discussion on fillin-the-blank standards.
5. Bulk-Power System v. Bulk Electric
System
60. As noted above, Commissionapproved Reliability Standards are to
provide for the Reliable Operation of the
Bulk-Power System. Generally speaking,
the Nation’s Bulk-Power System has
been described as consisting of
‘‘generating units, transmission lines
and substations, and system
controls.’’ 50 The transmission system
component of the Bulk-Power System is
understood to provide for the movement
of power in bulk to points of
distribution for allocation to retail
electricity customers. Essentially,
whereas transmission lines and other
parts of the transmission system,
including control facilities serve to
transmit electricity in bulk form from
the generation sources to concentrated
areas of retail customers, the
distribution system moves the
electricity to where these retail
customers consume it at a home or
business.
61. Section 215(b)(1) of the FPA
provides that all users, owners and
operators of the Bulk-Power System
must comply with Commissionapproved Reliability Standards. For
purposes of section 215, the statute
defines ‘‘Bulk-Power System’’ to mean:
(A) Facilities and control systems
necessary for operating an interconnected
electric energy transmission network (or any
portion thereof); and (B) electric energy from
generating facilities needed to maintain
transmission system reliability. The term
does not include facilities used in the local
distribution of electric energy.51

62. Notably, the statutory definition of
Bulk-Power System does not establish
voltage threshold limits on applicable
transmission facilities or electric energy
from generating facilities. It does,
however explicitly exclude facilities
used in the local distribution of
49 MOD–001, MOD–002, MOD–003, MOD–004,
MOD–005, MOD–008, and MOD–009.
50 Maintaining Reliability in a Competitive U.S.
Electricity Industry, Final Report of the Task Force
on Electric System Reliability, Secretary of Energy
Advisory Board, U.S. Department of Energy
(September 1998) at 2, 6–7.
51 16 U.S.C. 824o(a)(1).

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electricity. The NERC glossary, in
contrast, states that Reliability
Standards apply to the ‘‘bulk electric
system,’’ which is defined in terms of a
voltage threshold, as follows:
As defined by the Regional Reliability
Organization, the electrical generation
resources, transmission lines,
interconnections with neighboring systems,
and associated equipment, generally operated
at voltages of 100 kV or higher. Radial
transmission facilities serving only load with
one transmission source are generally not
included in this definition.52

63. While NERC’s definition generally
excludes transmission facilities
operated below 100 kV, NERC allows
each regional reliability organization to
add specificity to this general
obligation.
64. The Staff Preliminary Assessment
expressed concern that differences
between the statutory definition of BulkPower System and NERC’s definition of
bulk electric system create a
discrepancy that could result in
reliability gaps.53 Staff also expressed
concern that allowing a regional
reliability organization to define what
facilities are included in the bulk
electric system could result in
conflicting definitions—potentially
subjecting or excluding similar facilities
from compliance with the Reliability
Standards.
65. NERC recommends that, for the
initial approval of proposed Reliability
Standards, the continued use of NERC’s
definition of Bulk Electric System is
appropriate. In the longer term, NERC
suggests that change may be appropriate
but that any global change at this
juncture will affect many Reliability
Standards and is best achieved through
the Reliability Standards development
process. Some commenters emphasize
that all facilities necessary for BulkPower System reliability must be
covered by the Reliability Standards,
and none should be omitted by a
discretionary act of a regional reliability
organization. Many commenters,
however, state that these excluded
transmission systems have not been the
cause of any of the large blackouts and
therefore should not be considered as
part of the Bulk-Power System.54
52 See

NERC Petition, Exhibit A, NERC glossary

at 2.
53 Staff Preliminary Assessment at 25–26. For
example, the two 230 kV cables that connect
Mirant’s Potomac River Plant and the 69 kV
transmission facilities that supply portions of
Washington, DC were not included in the MAAC
definition of bulk electric system. New York City’s
138 kV system is not included in NPCC’s definition
of bulk electric system.
54 Staff review of selected Form No. 1 reports filed
with the Commission indicates that 25 percent or
more of many public utilities’ total transmission

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Furthermore, some commenters,
including those representing small
transmission owners, prefer the
continued use of the NERC definition
and caution against simply replacing all
references to bulk electric system with
Bulk-Power System because (1) the
latter term as defined in section 215 of
the FPA is ambiguous and (2) it would
likely lead to an unintended substantive
change in various Reliability Standards.
66. We believe that Congress intended
that the definitions of Bulk-Power
System and Reliable Operation 55 in
section 215 of the FPA to further the
objective of maintaining the reliability
of the entire Bulk-Power System,
including maintaining the reliability of
all of the elements of the transmission
component of the Bulk-Power System.
We believe that the transmission
elements excluded under NERC’s bulk
electric system approach, including
transmission that serves critical load
centers, are subject to the Commission’s
jurisdiction under section 215.
67. The term Bulk-Power System as
defined in section 215 of the FPA is one
determinant of the Commission’s
jurisdiction for reliability purposes (the
phrase ‘‘user, owner or operator’’ being
another). While we do not believe that
it is appropriate to categorically exclude
any class of facilities from the definition
of Bulk-Power System, we recognize
that a particular Reliability Standard
may appropriately only need to apply to
a subset of facilities that comprise the
Bulk-Power System. Thus, the
Commission may approve a Reliability
Standard that applies to the bulk
electric system as defined by NERC
without limiting the ability of the ERO
to develop and propose standards
applicable to the broader set of facilities
encompassed by the statutory definition
as may be necessary.
68. The Commission believes that the
ERO has suggested a sensible transition
approach. The Commission proposes
that, for the initial approval of proposed
line miles operate below 100 kV. Yet such facilities
may well be as much a part of an entity’s portion
of the nation’s integrated transmission system
component of the Bulk-Power System as the
transmission facilities operating at or above 100 kV
because these lower voltage facilities support the
higher voltage facilities. Indeed, it is not unusual
to see outages of 69 kV transmission facilities
limiting the higher voltage transmission facilities
with which they are networked.
55 As mentioned earlier, ‘‘Reliable Operation
means operating the elements of the Bulk-Power
System within equipment and electric system
thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading
failures of such system will not occur as a result
of sudden disturbance, including a Cybersecurity
Incident, or unanticipated failure of system
elements.’’ See Order No. 672 at P 64. See also 18
CFR 39.1.

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Reliability Standards, the continued use
of NERC’s definition of bulk electric
system as set forth in the NERC glossary
is appropriate.56 However, we interpret
the term ‘‘bulk electric system’’ to apply
to all of the ≥ 100 kV transmission
systems and any underlying
transmission system (< 100 kV) that
could limit or supplement the operation
of the higher voltage transmission
systems. It would also include
transmission to all significant local
distribution systems (but not the
distribution system itself), load centers,
and transmission connecting generation
that supplies electric energy to the
system. If there is a question concerning
which underlying transmission system
limits or supplements the operation of
the higher voltage transmission system,
the Commission proposed that the ERO
would provide the final determination
on a case by case basis.
69. Continued reliance on multiple
regional interpretations of the NERC
definition of bulk electric system, which
omits significant portions of the
transmission system component of the
Bulk-Power System that serve critical
load centers, is not appropriate. We
propose that NERC eventually revise the
current definition of bulk electric
system to ensure that all facilities,
control systems, and electric energy
from generation resources that impact
system reliability are included within
the scope of applicability, and that
NERC’s revision is consistent with the
statutory term Bulk-Power System.
70. While the approach outlined
above may result initially in a
Reliability Standard applying to a set of
Bulk-Power System facilities that is less
than that of the full reach of the
Commission’s jurisdiction pursuant to
section 215 of the FPA (the ‘‘gap’’ to
which the Staff Preliminary Assessment
referred), we agree with the commenters
that a wholesale substitution of one
term for another could lead to
unintended substantive changes within
certain Reliability Standards.
71. The Commission solicits comment
on this interpretation and whether the
Regional Entities should, in the future,
play a role in either defining the
facilities that are subject to a Reliability
Standard or be allowed to determine an
exception on a case-by-case basis.

56 We note that the regional definitions have not
been submitted to us and we are not determining
the appropriateness of any regional definition in
this proceeding.

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C. Mandatory Reliability Standards
1. Legal Standard for Approval of
Reliability Standards
72. Section 215(d)(2) of the FPA states
that the Commission may approve a
Reliability Standard if it determines that
a Reliability Standard is just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest. In Order No. 672, the
Commission addressed issues regarding
the application of the statutory standard
in our review of a proposed Reliability
Standard. The Commission identified a
series of factors it would consider when
assessing whether to approve or remand
a Reliability Standard.57 Further, Order
No. 672 stated that the Commission
would, consistent with the statute, give
‘‘due weight’’ to the technical expertise
of the ERO with respect to the content
of a proposed Reliability Standard.
However, due weight does not equate to
a rebuttable presumption that a
proposed Reliability Standard meets the
statutory requirement of being just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.58 Further, the Commission
review of a proposed Reliability
Standard would balance any conflict
between a proposed Reliability Standard
and competition on a case-by-case
basis.59
73. NERC suggests that a proposed
Reliability Standard that has been
developed through its Reliability
Standards development process, which
has been certified by ANSI as being
open, inclusive, balanced and fair, is
assured to be ‘‘just, reasonable, and not
unduly discriminatory or
preferential.’’ 60 NERC also proposes 10
‘‘benchmarks’’ for evaluating a proposed
Reliability Standard that, according to
NERC, ‘‘may be helpful’’ to the
Commission in determining whether a
Reliability Standard is ‘‘just, reasonable
and not unduly discriminatory or
preferential’’ if due process provided by
the ANSI process alone does not
suffice.61 In addition, NERC suggests
that the Commission should consider
the benchmarks when determining
whether a proposed Reliability Standard
‘‘is in the public interest.’’
74. In Order No. 672, the Commission
rejected the notion that it would
57 Order

No. 672 at P 262, 321–37.
at P 345.
59 Id. at P 378.
60 NERC Petition at 6–8.
61 Id. at 9–12. The benchmarks are: Applicability;
purpose; performance requirements; measurability;
technical basis in engineering and operations;
completeness; consequences for noncompliance;
clear language; practicality; and consistent
terminology.
58 Id.

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presume that a proposed Reliability
Standard developed through an ANSIcertified process automatically satisfies
the statutory standard of review.62
While an open and transparent process
certainly is extremely important to the
overall success of implementing section
215 of the FPA, an evaluation of any
proposed Reliability Standard must
focus primarily on matters of substance
rather than procedure. We will,
therefore, review each Reliability
Standard in addition to the process
through which it was approved by
NERC to ensure that the Reliability
Standard is just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
75. Likewise, with regard to NERC’s
benchmarks, we will not constrain
ourselves by approving or remanding a
proposed Reliability Standard based on
whether it satisfies the benchmarks. In
our order certifying NERC as the ERO,
we determined that the benchmarks and
other factors would be useful for the
ERO in developing proposed Reliability
Standards.63 The Commission did not
suggest that it would rely on the
benchmarks in its review of a proposed
Reliability Standard. Rather, as
discussed above, Order No. 672
identified factors that the Commission
will consider when determining
whether a proposed Reliability Standard
satisfies the statutory requirements.64
2. Commission Options When Acting on
a Reliability Standard
76. NERC recommends that the
Commission ‘‘conditionally approve’’
certain proposed Reliability Standards
that it believes satisfy the statutory
requirement but require improvement.65
The concept of conditional approval of
a Reliability Standard was discussed at
length in the July 6, 2006 technical
conference.66 Many commenters
responding to the Staff Preliminary
Assessment support some form of
conditional approval, while others
oppose the concept out of concern that
conditional approval will further
complicate the understanding of

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62 Order

No. 672 at P 338.
63 ERO Certification Order, 116 FERC ¶ 61,062, at
P 241.
64 Order No. 672 at P 262, 321–37.
65 See NERC Petition at 109; NERC Comments at
14–19.
66 July 6, 2006 technical conference, Tr. at 14–47.
According to NERC, conditional approval means
that the Commission would approve the Reliability
Standards as mandatory and enforceable. In
enforcing conditional standards, NERC and the
Regional Entities would factor into the
determination of violations and the imposition of
penalties that certain requirements may be regional
‘‘fill-in-the-blank’’ requirements or may be missing
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mandatory Reliability Standards and
present a ‘‘moving target’’ because
NERC has proposed a plan to modify
numerous proposed Reliability
Standards before the Commission would
approve them in a final rule.
77. The Commission believes that
conditional approval may be a useful
procedural tool that it may want to use
when reviewing a Reliability Standard
proposed at some future date. However,
after careful consideration, the
Commission is not proposing to
conditionally approve any of the 107
Reliability Standards currently before
us. Rather, as reflected in our
substantive analysis of each Reliability
Standard, we will propose one of four
actions:
78. Approve: Approval is appropriate
for a proposed Reliability Standard that
the Commission determines to be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest,’’ and as to which the
Commission has not identified any
additional issues that the ERO needs to
address at this time to improve the
Reliability Standard. Mandatory
compliance with the Reliability
Standard would be required as of the
effective date of the Final Rule. The
Commission has approved NERC’s plan
to review each Reliability Standard
within five years from the effective date
of the standard or its latest revision.
79. Approve as mandatory and
enforceable; and direct modification
pursuant to section 215(d)(5): The
Commission would take two separate
and distinct actions under the statute.
First, pursuant to section 215(d)(2) of
the FPA, the Commission would
approve a proposed Reliability
Standard, which would be mandatory
and enforceable upon the effective date
of the Final Rule. Second, the
Commission would direct NERC to
submit a modification of the Reliability
Standard to address specific issues or
concerns identified by the Commission
pursuant to section 215(d)(5) of the
FPA.67
80. This option is appropriate for a
large number of proposed Reliability
Standards where the Commission has
identified improvements which are
67 See ERO Certification Order at P 233, where the
Commission also noted that, if a Reliability
Standard is inadequate or has unintended
consequences, it may order the ERO to submit a
modification pursuant to section 215(d)(5) of the
FPA, 16 U.S.C. 824o(d)(5), which provides that
‘‘[t]he Commission * * * may order the Electric
Reliability Organization to submit to the
Commission a proposed reliability standard or
modification to a reliability standard that addresses
a specific matter if the Commission considers such
a new or modified reliability standard appropriate
to carry out this section.’’

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necessary or appropriate, but where the
proposed Reliability Standard
nonetheless satisfies the statutory
requirement that it be just, reasonable,
not unduly discriminatory or
preferential, and in the public interest.
This approach also allows us to give due
weight to the technical expertise of the
ERO in approving a Reliability
Standard, yet also provides a
mechanism to have the Commission’s
concerns addressed. Thus, where
appropriate, we propose to approve
these Reliability Standards as
mandatory and enforceable, and direct
modifications pursuant to section
215(d)(5). For these Reliability
Standards, we provide guidance with
regard to how and why they need to be
improved and may establish a deadline
by which a modification must be
resubmitted to the Commission.
81. Request additional information:
There are some Reliability Standards
that do not contain sufficient
information to enable us to propose a
disposition. For those Reliability
Standards, we will identify the
information that we require, and
propose not to approve or remand these
Reliability Standards until all the
relevant information is received. For
example, many of the fill-in-the-blank
Reliability Standards will not be
approved or remanded until the
Commission has received all the
necessary information. We may set a
deadline by which NERC must submit
the necessary information.
82. Remand: Remand is appropriate
for a proposed Reliability Standard that
does not satisfy the statutory criteria
that it be ‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ The Commission
may choose to set a deadline for NERC
to submit a modified Reliability
Standard.68 In the interim, the
remanded standard would not be
mandatory and enforceable. The
Commission will not hesitate to remand
a Reliability Standard that it finds does
not provide for an adequate level of
reliability.69
3. Prioritizing Modifications to
Reliability Standards
83. As discussed above, the
Commission is proposing to approve
certain Reliability Standards and, as a
separate action, is proposing to direct
the ERO to modify many of the same
Reliability Standards pursuant to
section 215(d)(5) of the FPA. The
68 See 18 CFR 39.5(g) (‘‘[t]he Commission, when
remanding a Reliability Standard * * * may order
a deadline by which the [ERO] must submit a * * *
modified Reliability Standard’’).
69 Order No. 672 at P 329.

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Commission recognizes that it is not
reasonable to expect the modification of
such a substantial number of Reliability
Standards in a short period of time.
Rather, the ERO will have to set
priorities regarding the order and timing
for developing modified Reliability
Standards and resubmitting them to the
Commission.
84. Many commenters recognize the
need for NERC to identify priorities in
terms of which Reliability Standards are
most critical to reliability and should be
revised immediately, and which are of
lesser priority. A number of
commenters, including WIRAB, suggest
detailed plans on how to set such
priorities, focusing primarily on
identifying those Reliability Standards
that are most critical to maintaining
reliability and those that are closest to
being ready for implementation.
Commenters suggest a staggered
schedule, some suggesting several years
for completion.
85. We propose that NERC first focus
its resources on modifying those
Reliability Standards that have the
largest impact on near term Bulk-Power
System reliability. Many of the
proposed modifications that reflect
Blackout Report recommendations fit
this description and should be a high
priority. The Commission has identified
a group of Reliability Standards that it
believes should be given the highest
priority by the ERO based on the above
guidance.70 However, this is not meant
to be an exclusive or inflexible list and
ERO and commenter input is welcome.
We propose that NERC address the
modifications we propose for these high
priority Reliability Standards within 1
year of the effective date of the Final
Rule.
86. In addition, we propose that NERC
address certain Reliability Standards
that are not necessarily identified above
as ‘‘high priority’’ may be modified in
a relatively short time frame where the
proposed modifications are relatively
minor or ‘‘administrative’’ in nature. We
believe that the ERO may complete such
modifications relatively quickly with
little diversion of ERO resources. Such
modifications may include a proposal to
modify a Reliability Standard to: (1)
Identify the ERO as the compliance
monitor rather than the regional
reliability organization; (2) include
Measures and Levels of Noncompliance; or (3) require other
relatively minor clarifications or
modifications.
87. While the Commission has
identified some modifications to
Reliability Standards that it believes
70 See

Appendix D (High Priority List).

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would be appropriate for the ERO to
resubmit as high priority items, we
believe that it is important that the ERO
develop a detailed, comprehensive work
plan to address all of the modifications
that are directed pursuant to a final rule.
The work plan should take a staggered
approach and complete all the proposed
modifications either within two or three
years from the effective date of the final
rule.
88. The Commission believes that this
proposal strikes a reasonable balance
between the need to timely implement
identified improvements to the existing
Reliability Standards that will further
Bulk-Power System reliability and the
need for the ERO to develop
modifications with industry input using
its open, stakeholder process. The
Commission may use its authority,
pursuant to § 39.5(g) of the
Commission’s regulations, to set a
deadline for the ERO to submit a
modified Reliability Standard if the
Commission is not satisfied with the
time frame proposed by the ERO work
plan.
89. The Commission solicits comment
on its prioritization proposal.
4. Trial Period
90. A number of commenters favor a
phase-in of Reliability Standards with a
trial period, during which Reliability
Standards would be mandatory, but no
penalties would be assessed.71 Various
commenters suggest that the trial period
should last for a range of six months to
five years.
91. NERC, in its application for ERO
certification, proposed a six month
‘‘notice period’’ during which NERC
would determine ‘‘financial’’ penalties
and provide notice of the penalties to
violating entities, but would not collect
any penalties. NERC stated that it would
submit a report on the effectiveness of
the revised Sanction Guidelines to the
Commission by May 31, 2007. In the
ERO Certification Order, the
Commission rejected requests to
lengthen NERC’s proposed six-month
‘‘notice period’’ because it
‘‘appropriately balances the time needed
for NERC to implement the Sanction
Guidelines with the countervailing
interest in activating the mandatory
Compliance Enforcement program as
rapidly as possible.’’ 72
92. The Commission, however, is
increasingly concerned that a trial
period that commences with the
effective date of mandatory Reliability
71 See, e.g., Alberta, APPA, ISO/RTO Council,
PSEG, WIRAB and WECC.
72 ERO Certification Order, 116 FERC ¶ 61,062, at
P 462.

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Standards may interfere with mandatory
and enforceable Reliability Standards
being in effect by next summer.
Moreover, the proposed Reliability
Standards have already been in effect
for a substantial period of time on a
voluntary basis. Thus, the Commission
proposes to eliminate a formal trial
period. Entities that have complied with
NERC’s standards on a voluntary basis
should be familiar with the proposed
mandatory Reliability Standards and
what is required for compliance.
Therefore, an extensive trial period is
unnecessary for such entities.
93. The Commission recognizes that
there are entities that have not
historically participated in the
voluntary system (including some
relatively small entities) that may not be
familiar with the proposed mandatory
Reliability Standards and what is
required for compliance. For such
entities, we propose that the ERO and
Regional Entities use their enforcement
discretion in imposing penalties on
such entities for the first six months the
Reliability Standards are in effect.
However, the Commission, the ERO,
and the Regional Entities would still
retain the authority to impose penalties
on such entities if warranted by the
circumstances.
5. International Coordination of
Remands
94. Canadian commenters, such as the
FPT Group, Alberta, CEA and Ontario
IESO, request that the Commission
affirm that it will seek to coordinate
with authorities in Canada prior to any
exercise of conditional approval,
remand or rejection of a proposed
Reliability Standard; and that each
existing NERC standard will retain its
present applicability until such time as
the Commission approves it as a
mandatory Reliability Standard.
95. The Commission has recognized
the importance of international
coordination in both Order No. 672 73
and the ERO Certification Order.74 In
the latter order, the Commission
directed NERC to revise its proposed
coordination process to: (1) Identify the
relevant regulatory bodies and their
respective standards approval and
remand processes that will be
implicated in any remand of a proposed
standard; and (2) specify actual steps to
coordinate all of these processing
requirements, including those that may
be necessary to expedite processing a
proposed Reliability Standard that must
be remanded. The Commission believes
73 See

Order No. 672 at P 400.
Certification Order, 116 FERC ¶ 61,062, at

74 ERO

P 286.

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that NERC’s development of a
coordination process, together with
existing means of communication and
coordination such as the U.S.—Canada
Bilateral Electric Reliability Oversight
Group, will provide the necessary
mechanisms for international
coordination.

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D. Common Issues Pertaining to
Reliability Standards
96. As explained in the Staff
Preliminary Assessment,75 certain
issues are common to a number of
proposed Reliability Standards.
Immediately below, we discuss these
common issues, followed by a
discussion and determination of each
individual proposed Reliability
Standard.
1. Blackout Report Recommendations
97. As explained in the Staff
Preliminary Assessment, the Blackout
Report identified a number of factors
common to eight major blackouts
experienced in North America since
1965 and made 46 specific
recommendations to improve reliability
based on the lessons learned from the
August 2003 blackout and previous
blackouts. These included specific
recommendations to modify certain
existing Reliability Standards. While
recognizing the progress NERC has
made, the Staff Preliminary Assessment
also expressed concern that the
proposed Reliability Standards continue
to reflect several of the deficiencies
identified by the Blackout Report.
98. In its comments, NERC
emphasizes that implementation of the
Blackout Report recommendations has
been its top priority since August 2003
and describes the progress it has made
in addressing specific recommendations
and the status of ongoing work. It states
that some of the hardest work on issues
such as relay loadability and reactive
power require extensive investigation
before standards can be drafted. Other
commenters suggest that the Blackout
Report recommendations provide useful
direction for areas where the Reliability
Standards require modification and for
setting priorities when determining
which Reliability Standards to modify
first. A few commenters ‘‘downplayed’’
the significance of the Blackout Report,
noting that there is no statutory basis to
accept all the Task Force’s
recommendations as absolute, infallible
requirements and that not all
recommendations translate into
Reliability Standards.
99. The Commission believes that the
Blackout Report recommendations

address key issues for assuring BulkPower System reliability. The Blackout
Report recommendations were
developed by and have received
international support from both
industry and regulators in the United
States and Canada and we believe they
represent a well-reasoned and sound
basis for action. Further, the Blackout
Report recommendations address issues
that caused or contributed to not only
the August 2003 blackout, but multiple
blackouts over the past 20 years.76 Thus,
in the discussion of a particular
proposed Reliability Standard, we often
will recognize the merit of a specific
Blackout Report recommendation and
reaffirm the reasoning behind such
recommendation in proposing to
approve with a directive to modify a
specific Reliability Standard. Further,
we believe that a modification to a
proposed Reliability Standard that was
recommended in the Blackout Report
should receive the highest priority in
terms of NERC’s workplan to address
identified deficiencies.
100. The Commission believes that
prudent policy for Bulk-Power System
reliability is to have Reliability
Standards that are proactive. Such
Reliability Standards would require
actions be taken to prevent a blackout or
outage and not simply address the
undesirable outcomes. Therefore, it
must first and foremost address the
critical steps or actions that determine
the achievement of the outcome. This
proactive approach is necessary to
ensure that the responsible entity is
aware of and performs all of the
necessary steps to achieve the ultimate
reliability goal, rather than reacting to
the implications of not achieving the
outcome.
101. Our concern is illustrated by an
analogy provided by NERC in regard to
commercial airline maintenance.77 A
purely outcome-based standard on
maintenance would require zero plane
crashes due to failure of airplane
components. But the public interest
would not be well served if this were
the only standard because the
consequences of failing to meet the
standard are immediate and
unacceptable and provides no guidance
on how to achieve the goal. The public
interest dictates that there should be
standards on maintenance procedures,
frequency of testing and qualifications
of personnel conducting the
maintenance—not just a requirement
that there be no accidents. This same
concept applies to mandatory Reliability
76 Blackout

75 See

Staff Preliminary Assessment at 17–26.

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Standards pertaining to the Bulk-Power
System.
102. Accordingly, the Commission
expects the ERO to include proactive
Requirements in the Reliability
Standards in addition to Requirements
that identify a specific outcome.
2. Measures and Levels of NonCompliance
103. As noted above, the uniform
format that NERC employs for each of
its proposed Reliability Standards
reflects five organizational elements:
Introduction, Requirements, Measures,
Compliance, and Regional Differences.
The Staff Preliminary Assessment stated
that 26 of the proposed Reliability
Standards do not contain Measures 78 or
Levels of Non-Compliance,79 or both.
The Staff Preliminary Assessment
emphasized that Reliability Standards
would be less subject to variable
implementation if they included the use
of performance metrics, where
applicable. The Staff Preliminary
Assessment assumed that metrics used
to determine non-compliance would be
included in the Measures similar to
BAL–001. NERC subsequently clarified
that such metrics are not intended to be
part of the Measure, but rather in the
Requirements.80
104. NERC, in its Petition, identified
21 Reliability Standards that lack
Measures or Levels of Non-Compliance
and indicated that it plans to file
modified Reliability Standards that
include the missing Measures and
Levels of Non-Compliance in November
2006. Further, NERC contends that a
Reliability Standard lacking Measures or
Levels of Non-Compliance is still
enforceable because the Measures
should be viewed as the process to
determine non-compliance during
audits and investigations. According to
NERC, the ‘‘Requirements’’ within a
Reliability Standard define what an
entity must do to be compliant and
establish an enforceable obligation, and
the presence or absence of Measures or
Levels of Non-Compliance should not
be the sole determining factor as to
whether a Reliability Standard meets
the statutory test for approval. Several
78 Although NERC does not formally define
‘‘Measures,’’ NERC explains that they ‘‘are the
evidence that must be presented to show
compliance’’ with a standard and ‘‘are not intended
to contain the quantitative metrics for determining
satisfactory performance.’’ NERC Comments at 104.
79 ‘‘Levels of Non-Compliance’’ are established
criteria for determining the severity of noncompliance with a Reliability Standard. The levels
of non-compliance range from Level 1 to Level 4,
with Level 4 being the most severe.
80 See NERC Comments at 105 (‘‘Metrics of
satisfactory performance are defined in the
requirements. * * *’’).

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commenters take the opposite view,
contending that Measures and Levels of
Non-Compliance are necessary to ensure
that a Reliability Standard is sufficiently
clear to be fairly enforced.81
105. We agree that it is important to
have Measures and Levels of NonCompliance specified for each
Reliability Standard, and recognize that
NERC has plans to provide many of
these elements in a November 2006
filing. However, the absence of these
two elements, which describe
approaches that will be used to assess
non-compliance, including the severity
of a violation for penalty settingpurposes, is not critical to our
determination of whether to approve a
proposed Reliability Standard. The most
critical element of a Reliability Standard
is the Requirements. As NERC explains,
‘‘the Requirements within a standard
define what an entity must do to be
compliant * * * [and] binds an entity
to certain obligations of performance
under section 215 of the FPA.’’ 82 If
properly drafted, a Reliability Standard
may be enforced in the absence of
specified Measures or Levels of NonCompliance.
106. While Measures and Levels of
Non-Compliance provide useful
guidance to the industry, compliance
will in all cases be measured by
determining whether a party met or
failed to meet the Requirement under
the specific facts and circumstances of
its use, ownership or operation of the
Bulk-Power System. Therefore, we
propose to approve a Reliability
Standard that lacks Measures or Levels
of Non-Compliance, or where these
elements contain ambiguities, provided
that the Requirement is sufficiently
clear and enforceable. Where a
Reliability Standard will be improved
by providing missing Measures or
Levels of Non-Compliance or by
clarifying ambiguities with respect to
Measures or Levels of Non-Compliance,
we propose to approve the Reliability
Standard and concurrently direct NERC
to modify the Reliability Standard
accordingly.
107. The common format of NERC’s
proposed Reliability Standards calls for
a ‘‘data retention’’ metric, generally in
the ‘‘Compliance’’ section of the
Reliability Standard. Yet, some
proposed Reliability Standards do not
contain a data retention requirement or
state positively that no record retention
period applies. The Commission seeks
comment on whether the retention time
periods specified in various Standards
81 See,

e.g., National Grid and BPA.
Comments at 104. See also NERC
Petition at 83.
82 NERC

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proposed by NERC are sufficient to
foster effective enforcement.83 The
Commission also seeks comment on
what, if any, additional records
retention requirements should be
established for the proposed Reliability
Standards.
3. Ambiguities and Potential Multiple
Interpretations
108. The Staff Preliminary
Assessment indicated that ‘‘various
elements of numerous standards appear
to be subject to multiple interpretations,
especially with regard to the lack of
specificity in the standards’
requirements, measurability, and
degrees of compliance.’’ 84 NERC agrees
that there are many areas in which the
Reliability Standards can be further
improved and states that it is committed
to review each Reliability Standard in
the next few years, based on priorities
coordinated with the Commission and
applicable authorities in Canada.85
NERC adds that, while there are
opportunities for improvement, the
existing Reliability Standards contain
the degree of clarity and specificity
required to meet the statutory test for
approval.
109. Many commenters agree
generally that ambiguities must be
removed and mandatory Reliability
Standards must be sufficiently clear
with regard to who is responsible and
what an entity must do to achieve
compliance.86 Some commenters insist
that a Reliability Standard should not go
into effect until this is achieved. WECC
and LPPC recommend that the
Commission require NERC to institute a
quality assurance program to ensure that
Reliability Standards are clear, concise,
and non-redundant.
110. Our review of the Reliability
Standards has confirmed staff’s concern
regarding the degree of ambiguity
contained in certain Measures and
Levels of Non-compliance portions of
the proposed Reliability Standards. We
83 Notably, the Commission elsewhere imposes
records retention requirements to facilitate effective
enforcement. For example, in Order No. 677, FERC
Stats. & Regs. 31,218 (2006), the Commission
amended 18 CFR parts 35 and 284 by extending
certain sellers’ record retention requirement from
three to five years so as to bring the record retention
requirement in line with the five year limitations
period applicable where the Commission might
seek to impose civil penalties for violations of the
anti-manipulation rule, 18 CFR part 1c. In the
reliability context, the civil penalty statute of
limitations period for both the Commission and
ERO and Regional Entities will also be five years.
See Order No. 672 at P 487.
84 Staff Preliminary Assessment at 18–19.
85 NERC Petition at 90–91; NERC Comments at
101–02.
86 See, e.g., LPPC, MISO, NEMA, SDG&E and
WECC.

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are pleased that the ERO intends to
review each Reliability Standard to
identify and address ambiguous
Measures and Levels of NonCompliance language. While this is
important, it is essential that the
Requirements for each Reliability
Standard, in particular, are sufficiently
clear and not subject to multiple
interpretations. Where the Requirements
portion of a Reliability Standard is
sufficiently clear (and no other issues
have been identified), we propose to
approve the Reliability Standard.
111. In other cases, where some
ambiguity may exist but there is also a
common interpretation for certain terms
based on the best practices within the
industry, we propose to adopt that
interpretation in the NOPR. For
purposes of enforcement, the
Commission proposes to implement any
approved Reliability Standard
consistent with our interpretation of any
ambiguity as explained in the final rule.
In some cases, we propose to direct
NERC to supplement the language
pursuant to section 215(d)(5) of the
FPA.
112. In summary, the Commission
believes that a proposed Reliability
Standard that has Requirements that are
so ambiguous as to not be enforceable
should be remanded. A Reliability
Standard that has sufficiently clear
Requirements, Measures, and
Compliance language and is otherwise
just and reasonable should be approved.
A proposed Reliability Standard that
has sufficiently clear and enforceable
Requirements but Measures or Levels of
Non-Compliance that are ambiguous (or
none at all) should be approved in some
cases with a directive that the ERO
develop clear and objective Measures
and Compliance language.
4. Technical Adequacy
113. The Staff Preliminary
Assessment stated that the
Requirements specified in certain
Reliability Standards may not be
sufficient to ensure an adequate level of
reliability.87 Staff explained that, while
Order No. 672 noted that the ‘‘best
practice’’ may be an inappropriately
high standard, it also warned that a
‘‘lowest common denominator’’
approach is unacceptable if it is
insufficient to ensure system reliability.
114. NERC, EEI and others state that
NERC’s proposed Reliability Standards
are technically sound and that
compliance with them will assure
reliability. NERC contends that each
proposed Reliability Standard meets the
statutory test of providing an adequate
87 Staff

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level of reliability for the Bulk-Power
System. Others share staff’s concern that
Reliability Standards not represent the
lowest common denominator.88 One
commenter suggested that there is a
tendency for a standard drafting team to
adopt a lowest common denominator
approach to achieve a consensus on a
standard.
115. We are cautious about drawing
any general conclusions about technical
adequacy as we consider this a matter
that can only be addressed on a
standard-by-standard basis. While we
are required under the statute to accord
due weight to the technical expertise of
the ERO, we are still required to
independently assess the technical
adequacy of any proposed Reliability
Standard. Where we have specific
concerns regarding whether a
Requirement set forth in a proposed
Reliability Standard may not be
sufficient to ensure an adequate level of
reliability or represents a ‘‘lowest
common denominator’’ approach, we
address those concerns in the context of
that particular Reliability Standard.
5. Fill-in-the-Blank Standards
116. Certain Reliability Standards
developed by NERC require the regional
reliability organizations to develop
criteria for use by users, owners, or
operators within the region. NERC refers
to these as ‘‘fill-in-the-blank
standards.’’ 89 NERC originally proposed
39 fill-in-the-blank standards, which it
said fell into three categories. The first
14 were Reliability Standards that
require a regional reliability
organization to set regional criteria or
develop a regional procedure.90 The
second group contained 10 Reliability
Standards that require the regional
reliability organization to develop such
criteria or procedures, and also require
entities within the region to follow
those procedures or criteria.91 The third
category consisted of 15 Reliability
Standards that require users, owners,
and operators to follow criteria or
procedures developed by the regional
reliability organization, but did not (in
the same Reliability Standard) require
the development of such criteria or
procedures.92 NERC indicated that the
88 See,

e.g., NPCC, SDG&E and NYSRC.
NERC Petition at 87–90.
90 EOP–007, IRO–001, MOD–003, MOD–011,
MOD–013, MOD–014, MOD–015, MOD–016, PRC–
002, PRC–003, PRC–006, PRC–012, PRC–013, and
PRC–014.
91 BAL–002, EOP–004, MOD–001, MOD–002,
MOD–004, MOD–005, MOD–008, MOD–009, MOD–
024, and MOD–025.
92 EOP–009, FAC–001, FAC–002, FAC–004,
MOD–010, MOD–012, MOD–017, MOD–019, PER–
002, PRC–004, PRC–007, PRC–008, PRC–009, PRC–
015, and PRC–016.

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89 See

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first category did not pose a problem
because they were enforceable as
written. The issue with the remaining
25 Reliability Standards was whether
they could be enforced given that the
regional criteria and procedures were
not developed through an EROapproved process and were not
submitted to the Commission for
approval. NERC acknowledged that the
25 fill-in-the blank Reliability Standards
in categories two and three required
further evaluation and proposed
providing a work plan to the
Commission by November 8, 2006 with
a timetable for modifying, replacing, or
withdrawing these standards.93
117. The Staff Preliminary
Assessment recognized that the fill-inthe-blank standards raise two principal
concerns: (i) Some are not enforceable
against users, owners, and operators of
the Bulk-Power System, but rather only
provide broad direction to regional
reliability organizations, and (ii) the
specific implementing standards
adopted by the regional reliability
organizations have not undergone an
approval process under section 215 and,
thus cannot be enforced by the
Commission or the ERO.
118. In its June 26, 2006 comments to
the Staff Preliminary Assessment, NERC
amended its approach to the fill-in-theblank standards. It recommends
unconditional approval of the ‘‘category
one’’ Reliability Standards, which place
a requirement on a regional reliability
organization to set criteria or procedures
for reliability in the region, claiming
that they are really not fill-in-the-blank
standards. NERC then proposes to
divide the remaining fill-in-the-blank
standards into two new groups, the first
group consisting of 26 Reliability
Standards.94 The remaining group
consists of three fill-in-the-blank
standards that also are missing measures
or compliance elements.95 NERC
93 NERC

Petition at 89.
group includes 24 of the 25 standards
originally included in categories two and three,
plus two additional standards not originally
designated as fill-in-the-blank standards: BAL–002–
0, EOP–009–0, FAC–001–0, FAC–002–0, FAC–004–
0, MOD–001–0, MOD–002–0, MOD–004–0, MOD–
005–0, MOD–008–0, MOD–009–0, MOD–010–0,
MOD–012–0, MOD–017–0, MOD–019–9, MOD–
024–1, MOD–025–1, PER–002–0, PRC–004–1, PRC–
007–0, RPC–008–0, PRC–009–0, PRC–015–0, PRC–
016–0, TPL–002–0,* and TPL–004–0.* (* Newly
identified as fill-in-the-blank standards.)
95 EOP–004–0, EOP–006–0,* and IRO–005–1.*
(* Newly identified as fill-in-the-blank standards.)
NERC proposes that these 3 standards, along with
23 others that are missing measures or compliance
elements be conditionally approved with the
understanding that the missing measures and
compliance information will be filed in November
2006, after completion of stakeholder balloting in
September and NERC board voting on November 1,
2006.
94 This

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recommends conditional approval of
these 29 remaining fill-in-the-blank
standards.
119. Some commenters raised
concerns that the fill-in-the-blank
standards undermine uniformity, and
may exacerbate differences or seams
between the various ISO and RTO
control areas. Several commenters
support limited use of fill-in-the-blank
standards, noting that they provide
flexibility, which may facilitate
development of a Reliability Standard in
instances where a continent-wide
approach may not work.
120. NERC represents that it will
submit an action plan and schedule in
November 2006 for completing the fillin-the-blank standards. NERC expects
that it will take approximately three
years to complete the process, and will
be prioritizing Reliability Standards that
require the most immediate revision.96
NERC anticipates three potential
approaches to the fill-in-the-blank
standards: (1) If NERC determines that
there is insufficient justification for a
regional difference, it may replace a
Reliability Standard with a uniform
continent-wide Reliability Standard; (2)
where a regional difference is justified,
NERC proposes to direct the regions to
develop their regional criteria as a
Reliability Standard to be filed for
approval with the ERO and thereafter
with the Commission and applicable
authorities in Canada; (3) if mandatory
enforcement of a fill-in-the-blank
standard is not necessary for reliability,
NERC proposes to retire the Reliability
Standard and allow a region to maintain
voluntary criteria and procedures as
needed.
121. We share commenters’ concerns
regarding the potential for the fill-inthe-blank standards to undermine
uniformity. Order No. 672 stated that,
while uniformity is the goal with
respect to Reliability Standards, it may
not be achievable overnight. Where
NERC had directed the regions to
develop a particular Reliability
Standard, we noted that ‘‘[o]ver time,
we would expect that the regional
differences produced under this
framework will decline and a set of best
practices will develop.’’ 97 NERC’s
review states it will take uniformity
concerns into consideration, only
permitting regional differences where
justified. In Order No. 672, we specified
two instances where regional
differences may be permitted: regional
differences that are more stringent than
the continent-wide Reliability Standard,
including those addressing matters not
96 NERC
97 Order

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addressed by a continent-wide
Reliability Standard, and regional
differences necessitated by a physical
difference in the Bulk-Power System.98
NERC’s review must be consistent with
these criteria.
122. In addition, if after an
appropriate review, NERC determines
that regional differences are still
warranted, we propose that any regional
proposal to fill-in-the-blank must be
developed in accordance with the
NERC’s ANSI-approved process, or
through an alternative process approved
by the ERO,99 and must be submitted to
the ERO and the Commission for
approval.
123. We propose to require
supplemental information regarding any
Reliability Standard that requires a
regional reliability organization to fill in
missing criteria or procedures. Where
important information has not been
provided to us to enable us to complete
our review, we are not in a position to
approve those Reliability Standards.
Therefore, we propose to not approve or
remand those Reliability Standards until
all the necessary information has been
provided.
E. Discussion of Each Individual
Reliability Standard

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124. We have reviewed each of the
proposed Reliability Standards, and our
analysis is by chapter according to the
categories of Reliability Standards
defined in NERC’s petition. Each
chapter begins with an introduction to
the category, followed by a discussion of
each proposed Reliability Standard. The
discussion includes summaries of
NERC’s proposal, the Staff Preliminary
Assessment, and comments received, as
well as a Commission proposal. The
Commission proposal for each standard
will include a proposed disposition. For
Reliability Standards that are proposed
to be approved with direction that
NERC modify the Reliability Standard,
specific instructions are provided
regarding areas that need to be
modified, and how they should be
modified. Where additional information
is needed in order for the Commission
to propose a disposition, the
information required will be detailed.
98 Id. at P 291. Our position was reiterated in the
ERO Certification Order where we directed NERC
to delete additional criteria contained in its Rules
of Procedure and Reliability Standard development
procedures. ERO Certification Order, 116 FERC
¶ 61,062, at P 274.
99 NERC Rule of Procedure section 312.4 states
that regional Reliability Standards ‘‘may be
developed through the NERC reliability standards
development procedure, or alternatively, through a
regional reliability standards development
procedure that has been approved by NERC.’’

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1. BAL: Resource and Demand
Balancing
a. Overview of Category
125. The six Balancing (BAL)
Reliability Standards address balancing
resources and demand to maintain
interconnection frequency within
prescribed limits.
i. General Comments
126. LPPC comments generally that
each Requirement contained in a
Reliability Standard must be measurable
to be mandatory. In this regard, LPPC
identifies examples of Requirements in
the BAL Standards that it claims are not
measurable requirements but, rather,
descriptive or explanatory statements.
LPPC also identifies several
Requirements in the BAL Standards that
it claims are redundant to other
Requirements in the BAL Standards.
127. CenterPoint comments that
significant regional variation ‘‘is
necessary in matters such as amount
and composition of spinning reserve
and calculation of the Frequency Bias
component of ACE due to the different
operating characteristics of the
regions.’’ 100 CenterPoint suggests that
customers’ concerns are focused on
ensuring that a Reliability Standard’s
performance requirements are met as
opposed to concerns about specifically
how these requirements are met.
CenterPoint indicates that regional
variation in the method to comply with
the Reliability Standard is acceptable so
long as the Reliability Standard’s
required level of performance is
ultimately achieved. CenterPoint
suggests that certain process-oriented
Reliability Standards in this group
should be eliminated because other BAL
Reliability Standards already include
metrics necessary to determine
compliance.
ii. Commission Response
128. With respect to LPPC’s general
comments, the Commission agrees that
Reliability Standards must have clear
and enforceable Requirements. LPPC
correctly identifies a number of
instances in the BAL Reliability
Standards where a Requirement appears
to entirely consist of, or contain, an
explanatory statement rather than an
actionable Requirement. While the
Commission agrees with LPPC that
explanatory statements should not be in
the Requirements section of a Reliability
Standard, the presence of an
explanatory statement does not render
the Reliability Standard unenforceable.
The Commission has addressed the
100 CenterPoint

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64785

redundant Requirements identified by
LPPC within the applicable Reliability
Standards below.
129. With respect to CenterPoint’s
comment, the Commission believes
there are certain processes, such as the
methods for calculating frequency bias,
which are accepted industry practices
and should be included as uniform
requirements in the Reliability
Standards. The Commission proposes to
formalize the process across the regions.
This will protect reliability by providing
a common basis for analysis and
corrective actions. CenterPoint also
comments that ‘‘some of the processoriented standards should be
eliminated,’’ but because CenterPoint
provided no further detail on this point,
the Commission is unable to fully
consider and respond to the comment.
b. Real Power Balancing Control
Performance (BAL–001–0)
i. NERC Proposal
130. The purpose of this Reliability
Standard is to maintain Interconnection
steady-state frequency within defined
limits by balancing real power demand
and supply in real-time. BAL–001–0
establishes two requirements that are
used to assess the proficiency of a
balancing authority to maintain
interconnection frequency by balancing
real power (MW) demand, interchange,
and supply. The proposed Reliability
Standard would apply to balancing
authorities.
ii. Staff Preliminary Assessment
131. Staff commented that
BAL–001–0 provides a good example of
performance metrics useful for assessing
the performance of Balancing
Authorities and compliance with the
standard.
iii. Comments
132. ReliabilityFirst agrees with staff’s
comments, and ISO/RTO Council
recommends that the Commission
accept this Reliability Standard.
133. LPPC asserts that Requirements
R1 and R2 are not actual Requirements
but instead only determine whether the
balancing authority has adequate
regulating reserves, without specifying a
performance metric.
iv. Commission Proposal
134. The Commission disagrees with
LPPC’s comment that Requirements R1
and R2 are not actual Requirements. To
the contrary, Requirements R1 and R2
state the bounds within which a
balancing authority must control its area

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control error (ACE).101 For example,
Requirement R2 requires each balancing
authority to operate such that its average
ACE for at least 90 percent of the time
is within a specific limit. These
Requirements set forth an effective
means for maintaining Interconnection
steady-state frequency errors that are
consistent with historic Interconnection
frequency performance, which is the
stated goal of BAL–001–0. These
Requirements also have associated
Measures and Levels of NonCompliance.
135. BAL–001–0 provides for an
important function necessary to
maintain Bulk-Power System reliability.
Further, the Commission agrees with
NERC’s proposed applicability of this
standard to balancing authorities.
136. For the reasons discussed above,
the Commission believes that Reliability
Standard BAL–001–0 is just, reasonable,
not unduly discriminatory or
preferential, and in the public interest;
and proposes to approve it as mandatory
and enforceable.
c. Regional Difference to BAL–001–0:
ERCOT Control Performance Standard 2
i. NERC Proposal

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137. NERC approved a regional
difference for ERCOT from Requirement
R2 in BAL–001–0, which requires that
the average area control error or ‘‘ACE’’
for each of the six ten-minute periods
during the hour must be within specific
limits, and that a balancing authority
achieve 90 percent compliance.102 This
Requirement is referred to as Control
Performance Standard 2 (CPS2). NERC
explains that ERCOT requested a waiver
of CPS2 because: (1) ERCOT, as single
control area 103 asynchronously
connected to the Eastern
Interconnection, cannot create
inadvertent flows or time errors in other
control areas; and (2) CPS2 may not be
feasible under ERCOT’s competitive
balancing energy market. In support of
this argument, ERCOT cites to a study
which it performed showing that under
the new market structure, the ten
101 NERC defines ACE as ‘‘The instantaneous
difference between a Balancing Authority’s net
actual and scheduled interchange, taking into
account the effects of frequency Bias and correction
for meter error.’’
102 Each regional difference approved by NERC is
provided as a separate ‘‘waiver request’’ document
that identifies the entity requesting a waiver, the
Reliability Standard or Requirements that are
waived, and explanation and a statement of NERC
approval. See NERC Petition, Exhibit A. In addition,
each regional difference is identified in the
Reliability Standard to which the waiver applies.
103 At the time NERC granted this regional
difference, the term ‘‘control area’’ was used instead
of ‘‘balancing authority.’’ For purposes of this
discussion, they are the same.

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control areas in its region were able to
meet CPS2 standards while the
aggregate performance of the ten control
areas was not in compliance.
ii. Staff Preliminary Assessment
138. This regional difference was not
addressed in the Staff Preliminary
Assessment.
iii. Comments
139. There were no comments
regarding this regional difference.
iv. Commission Proposal
140. Order No. 672 explains that
‘‘uniformity of Reliability Standards
should be the goal and the practice, the
rule rather than the exception.’’ 104
However, 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.105 Regional
differences must still be just, reasonable,
not unduly discriminatory or
preferential and in the public
interest.106
141. ERCOT’s Protocols concerning
frequency control identify that the
existing ERCOT approach to
Interconnection frequency control is
necessary to assure reliability in that
interconnection.107 However, the
existing waiver was filed prior to the
formation of these procedures. ERCOT
is both a single balancing authority and
the smallest of the three
Interconnections, approximately one
tenth of the size of the Eastern
Interconnection. As such, frequency
control is more critical to its system
reliability.108
142. The Commission notes that the
physical difference of ERCOT compared
to the other two interconnections in
terms of size is a sufficient reason for
approving a regional difference. Also,
ERCOT’s approach of determining the
minimum frequency response needed
for reliability and requiring appropriate
generators to have specific governor
droop appears to be a more stringent
practice than Requirement R2 in BAL–
104 Order
105 Id.

No. 672 at P 290.
at P 291.

106 Id.
107 See ERCOT Protocols, section 5 (Dispatch) at
21–23 (May 1, 2006), available at: http://
www.ercot.com/mktrules/protocols/current.html.
108 The minimum frequency response as
calculated by ERCOT for reliable operation is 420
MW/0.1 Hz, while the measured frequency
response for the Eastern Interconnection is
approximately 3,000 MW/0.1 Hz. ERCOT has a
requirement for a minimum frequency bias that is
almost twice that of the Eastern Interconnection
taken on the same total load basis.

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001–0. The calculation of the required
frequency response will be discussed in
BAL–002. However, neither reason is
articulated in the proposed regional
difference.
143. The Commission proposes to
approve the ERCOT regional difference.
However, the Commission proposes to
have the ERO submit a modification of
the ERCOT regional difference to
include the requirements concerning
frequency response contained in the
ERCOT Protocols, section 5.
d. Disturbance Control Performance
(BAL–002–0)
i. NERC Proposal
144. The reliability goal of this
Reliability Standard is to utilize
contingency reserves to balance
resources and demand to return
interconnection frequency to within
defined limits following a reportable
disturbance. BAL–002–0 establishes:
(1) The generic requirements that each
regional reliability organization should
use to determine the amount and type
of contingency reserves that will be
needed to meet a metric called the
Disturbance Control Standard (DCS); (2)
how to calculate the DCS metric; (3)
procedures to be used in calculating
DCS for reserve sharing groups; (4) a 15
minute default disturbance recovery
period; (5) a 90 minute default
contingency reserve restoration period;
and (6) the requirement that balancing
authorities have access to contingency
reserves to respond to loss of generation,
but not loss of load. The proposed
Reliability Standard would apply to
balancing authorities, reserve sharing
groups,109 and regional reliability
organizations.
ii. Staff Preliminary Assessment
145. Requirement R3.1 requires that a
balancing authority or reserve sharing
group carry ‘‘at least enough
contingency reserves to cover the most
severe single contingency.’’ Staff noted
that the Requirement could be subject to
multiple interpretations, one limited to
only the loss of generation, whereas the
other considers the loss of supply
resulting from a transmission or
generation contingency.110 Further staff
noted that specific requirements related
to the composition of reserves and the
restoration time are left to Regions and
sub-Regions to determine. For example,
Requirement R2 directs each regional
reliability organization (or sub-regional
109 A ‘‘reserve sharing group’’ is a group of two
or more balancing authorities that collectively
maintain, allocate and supply operating reserves.
See NERC glossary at 12.
110 Staff Preliminary Assessment at 30.

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reliability organization or reserve
sharing group) to specify its contingency
reserve policies, including minimum
reserve requirements and allocation and
the permissible mix of reserves. Other
provisions identified by staff as vague or
missing include the definition as to
which resources and demand side
management are eligible to be counted
as spinning reserves. Finally, staff stated
that lower reporting thresholds for the
size of the minimum disturbance, which
may be required by certain regional
reliability organizations, should be
documented as a regional difference.
iii. Comments
146. NERC states that, with regard to
contingency reserves, the BAL–002–0
requirement that a balancing authority
restore its resource-demand balance
with the rest of the Interconnection
within 15 minutes is absolute, objective
and measurable. To meet this
requirement, the balancing authority
must have available sufficient reserves
to recover from the largest single
contingency and deploy those reserves
within 15 minutes. It states that
‘‘leaning on the system’’ for up to 15
minutes is an appropriate use of the
Interconnection. Thus, with regard to
staff’s comments that the Reliability
Standard does not specify minimum
reserve requirements and that the
appropriate mix of reserves is not
defined, NERC questions whether it is
appropriate to measure the desired
outcome (as BAL–002–0 does), or how
that outcome is achieved (as staff
suggests). NERC suggests that the
existing approach is more appropriate
because the ‘‘how’’ portion is driven by
system design, resource mix and
economics. Further, it adds that regional
variation is appropriate in determining
the amount of contingency reserves
because it is driven by the specific
system configuration and operating
conditions; and adding greater
specificity to the contingency reserve
requirements to achieve uniformity will
not enhance reliability but will likely
increase costs of compliance. NERC
states that it will review the potential
reliability benefits and costs associated
with more specific and uniform
contingency reserve requirements.
147. Many commenters agree with the
Staff Preliminary Assessment that BAL–
002–0 lacks specificity in certain areas.
Most commenters also argue in favor of
giving deference to regions or reserve
sharing groups with regard to the
requirements in Requirement R2 and
certain other requirements of the
standard. CPUC states that the
corresponding WECC standards provide
specificity in areas identified by staff

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and provide for a more stringent
disturbance reporting threshold. It
suggests that the Commission defer to
and approve such regional standards
already in place that correspond to
NERC-proposed Reliability Standards,
but add specificity and stringency
without triggering a need for the
regional reliability organization to
provide extensive justification for a
‘‘regional difference.’’ ISO/RTO Council
states that ‘‘the requirements to recover
the loss of generation and returning
Area Control Error to a specified value
within a specific time period as
stipulated in the standard provide the
needed reliability performance
yardstick.’’ 111 It continues, stating that
once these performance-based
requirements are in place, the regional
reliability organization standards can
provide the supplementary process
requirements. MidAmerican advocates
that the appropriate reserve sharing
group should specify requirements for
contingency reserves, while CenterPoint
states that a significant amount of
regional variation is necessary.
ReliabilityFirst believes that NERC
should provide a clear definition of
spinning reserves for Interconnections.
148. MidAmerican suggests that there
should be specific requirements such as
the percentage of reserves to load, the
permissible mix of spinning reserves
verses non-spinning generation to meet
operating reserves, the maximum
allowable interruptible load, and other
pool rules. These requirements should
be based on composite reliability
studies such as a Loss-of-Load
Expectation (LOLE) 112 in the
Interconnection. It also states that BAL–
002–0 should contain a planning reserve
requirement 113 based on LOLE.
MidAmerican suggests that BAL–002–0
should allow for differing regional
reserve requirements due to differing
generation mixes in each region.
149. ReliabilityFirst agrees with staff’s
assessment. It comments that the loss of
supply is another contingency and
suggests that the Reliability Standard
should further define the criteria for
contingencies and state the requirement
for all types of contingencies to be
assessed during recovery from a
111 ISO–RTO

Council Comments, Attachment A

at 3.
112 LOLE studies are probabilistic studies
associated with determining the probability that
there may not be sufficient generation to supply
firm load.
113 Contingency reserves are those reserves used
during real time operation to accommodate
uncertainties in generation failures. In contrast,
planning reserves have a long-term perspective.
While BAL–002–0 has a requirement pertaining to
contingency reserve policy, the Reliability
Standards are silent on planning reserve.

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64787

disturbance. ReliabilityFirst also agrees
that lower thresholds should be defined
as regional differences but any
difference should be demonstrated as
technically defensible and warranted.
ReliabilityFirst agrees with the Staff
Preliminary Assessment that the
procedures developed by the individual
regions to determine contingency
reserves need to be merged to develop
consistency.
150. LPPC points out several
Requirements it considers problematic.
It states that Requirement R4.1 is not a
requirement but rather a definition of
some of the criteria for disturbance
recovery. It further states that the
statement in Requirement R4.1, is only
true if the balancing authority is not
utilizing a reserve sharing group to
respond to the event, and the definition
should be expanded to include reserve
sharing groups. LPPC suggests that there
is some redundancy between
Requirements R4 and R5 and that they
could be combined. Specifically, LPPC
suggests that the first sentence of each
Requirement is essentially stating the
same thing. It also states the reference
to the NERC Operating Committee
should be removed from Requirements
R4.2 and R6.2.
iv. Commission Proposal
151. The Commission proposes to
approve BAL–002–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard as discussed
below.
152. The issues identified by the
commenters and staff can be grouped
into three categories: (1) The
measurement of the performance of the
contingency reserves through
Disturbance Control Standard; (2) the
determination of the amount and
makeup of contingency reserves; and (3)
what contingencies are appropriate to
consider.
(a) Disturbance Control Standard
153. NERC contends that this
standard is ‘‘absolute, objective, and
measurable’’ in that it allows up to 15
minutes for the recovery from a
disturbance.114 The Commission agrees
with allowing up to 15 minutes for
recovery from a disturbance. To achieve
NERC’s measurement approach, we
propose that NERC modify Requirement
R3.1, which currently requires that a
balancing authority carry at least
enough contingency reserve to cover
‘‘the most severe single contingency,’’ to
include enough contingency reserve to
cover any event or single contingency,
114 NERC

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including a transmission outage, which
results in a significant deviation in
frequency from the loss or mismatch of
supply either from local generation or
imports.115 We believe that this
approach would address staff’s concern
with Requirement R3.1 while giving due
weight to the ERO’s position. Further,
NERC should consider whether a
frequency deviation of 20 milli Hertz
lasting longer than the 15 minute
recovery period should be used to
define a significant deviation in
frequency. The Commission is aware
that this approach is consistent with the
Balancing Authority ACE Limit (BAAL)
presently being field tested. The major
difference between the proposal and the
BAAL is that the proposal is aimed at
preserving the historic frequency
performance of the system.
154. The Commission agrees with
ReliabilityFirst that lower reporting
thresholds for the size of the minimum
disturbance should be defined as a
regional difference. However, the above
approach eliminates that concern
because any event or single contingency
that causes a frequency deviation above
the defined threshold would be
included in the DCS calculation.

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(b) Determination of Amount and
Makeup of Contingency Reserves
155. The Commission notes that
Requirement R2 of BAL–002–0 is a ‘‘fillin-the-blank’’ requirement, as it directs
each regional reliability organization (or
sub-regional reliability organization or
reserve sharing group) to specify its
contingency reserve policies, including
minimum reserve requirements and
allocation and the permissible mix of
reserves. NERC and many other
commenters state that the regional
determination of contingency reserves is
appropriate.
156. While the Commission believes it
is appropriate for balancing authorities
to have different amounts of
contingency reserves, these amounts
should be based on one uniform
continent-wide contingency reserves
policy. The policy should be based on
the reliability risk of not meeting load
associated with a particular balancing
authority’s generation mix and topology.
The appropriate mix of operating
reserves, spinning reserves and nonspinning reserves should be addressed
on a consistent basis. As identified by
115 Although Frequency Response and Bias are
discussed at length in Reliability Standard BAL–
003–0, the Commission notes here that it is
important that contingency reserves should have
adequate frequency response to ensure recovery
immediately following an event.

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the ERCOT and WECC whitepapers,116
due consideration should be given to
the amount of frequency response from
generation or load needed to assure
reliability. We propose that this policy
be neutral as to the source of the
contingency reserves in terms of
ownership or technology. Accordingly,
the Commission proposes to require
NERC to develop a continent-wide
contingency reserve policy.
157. As identified in the Staff
Preliminary Assessment, the types of
resources that can be used for
contingency reserves should be
consistent across the country and not
have some regions allow the curtailment
of irrigation pumps (one form of DSM)
to be used as part of contingency
reserves while other regions do not.117
Demand Side Management or Direct
Control Load Management should be on
the same basis as conventional
generation or any other technology.
Accordingly, the Commission proposes
to direct NERC to modify BAL–002–0 to
include a Requirement that explicitly
allows demand side management as a
resource for contingency reserves.
158. With regard to MidAmerican’s
suggestion that the BAL–002–0
Reliability Standard should contain a
planning reserve requirement based on
LOLE, the Commission disagrees noting
that BAL–002–0 deals with operating
reserves and not planning reserves.
(c) Contingencies
159. Staff’s concern regarding
transmission contingencies is resolved
by the above approach in measuring
response for frequency deviation.
160. With regard to LPPC’s concerns,
the Commission disagrees with its
suggestion that the applicability of
Requirement R4.1 should be extended to
reserve sharing groups, noting that
reserve sharing groups typically do not
calculate a combined ACE. With regard
to LPPC’s comment regarding the
redundancy of R4 and R5 and the
suggestion that these requirements be
combined, we leave that to the
discretion of the ERO.
161. We agree with LPPC’s suggestion
to modify Requirements R4.2 and 6.2 of
BAL–002 to replace references to the
116 See WECC Frequency Response Standard
White Paper (2005), available at http://
www.wecc.biz/documents/library/RITF/
FRR_White_Paper_v12_1–27–06.pdf; ERCOT Energy
Market Technical Paper 1C, Defining, Measuring
and Valuing Frequency Response (January 2004).
117 See also Assessment of Demand Response and
Advanced Metering: Staff Report (Aug. 2006)
(Demand Response Report), available at http://
www.ferc.gov/legal/ staff-reports/demandresponse.pdf.

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NERC Operating Committee with the
ERO.118
162. While the Commission has
identified concerns with regard to BAL–
002–0, we believe that the proposal
serves an important purpose in ensuring
a balancing authority is able to utilize
its contingency reserves to balance
resources and demand and return
interconnection frequency within
defined limits following a reportable
disturbance. Further, the proposed
Requirements set forth in BAL–002–0
are sufficiently clear and objective to
provide guidance for compliance.
163. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard
BAL–002–0 as mandatory and
enforceable. In addition, pursuant to
section 215(d)(5) of the FPA and
§ 39.5(f) of our regulations, the
Commission proposes to direct that
NERC submit, a modification to BAL–
002–0 that: (1) Includes a Requirement
that explicitly allows demand side
management as a resource for
contingency reserves; (2) develop a
continent-wide contingency reserve
policy; 119 (3) includes a Requirement
that measures response for any event or
contingency that causes a frequency
deviation; (4) substitutes ERO for
regional reliability organization as the
compliance monitor; 120 and (5) change
references to the NERC Operating
Committee in Requirements R4.2 and
R6.2 to ERO.
e. Frequency Response and Bias
(BAL–003–0)
i. NERC Proposal
164. The purpose of BAL–003–0 is to
ensure that a balancing authority’s
frequency bias setting 121 is accurately
118 LPPC raises the same concern regarding
references to the NERC Operating Committee in
other Reliability Standards. We agree that the term
should be removed and replaced with the term ERO
in all such places.
119 This could be accomplished by modifying
Requirement R2 or developing a new Reliability
Standard.
120 The proposal to require that the ERO be
identified as the compliance monitor (which may
then choose to delegate compliance monitor
responsibility to a Regional Entity) applies to each
Reliability Standard that currently identifies the
regional reliability organization as the compliance
monitor. However, we will not repeat this proposal
throughout the NOPR.
121 Frequency bias setting is a value expressed in
MW/0.1 Hz, set into a balancing authority ACE
algorithm that allows the balancing authority to

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calculated to match its actual frequency
response.122 Among other things, BAL–
003–0 establishes: (1) A Requirement for
balancing authorities to review their
frequency bias calculation on an annual
basis to reflect any changes in their
frequency response and to update the
frequency bias to reflect changes to any
factors used in the calculation, and to
report frequency bias setting and
methodology used to the NERC
Operating Committee; (2) general
Requirements on how balancing
authorities should calculate frequency
bias, including which factors or
parameters to include in the calculation;
(3) a Requirement which establishes a
default frequency bias setting of 1
percent of yearly peak demand per 0.1
Hz for balancing authorities that serve
native load; and (4) for balancing
authorities that do not serve native load,
a Requirement which establishes a
default frequency bias setting of 1
percent of its estimated maximum
generation level in the coming year per
0.1 Hz. The proposed Reliability
Standard would apply to balancing
authorities.

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ii. Staff Preliminary Assessment
165. Staff raised the concern that use
of a frequency bias setting that is
different from the natural frequency
response of the balancing authority’s
area could result in less control actions
than are appropriate to preserve system
reliability.123 In addition, staff noted
that several metrics, such as ACE, CPS1,
and CPS2, use frequency bias setting as
an input and the use of an incorrect
value of frequency bias setting would
result in incorrect measurement of
actual performance with respect to ACE,
CPS1, and CPS2.
166. Staff noted that BAL–003–0 does
not specify the actual minimum
frequency response needed for reliable
operation and how the frequency
response should vary with the types of
generation used to ensure that all types
of generators are contributing their share
of frequency response to assure the
reliability of the Bulk-Power System.124
Further, staff expressed concern that
data from actual events show that the
natural frequency response for Eastern
contribute its frequency response to the
Interconnection. See NERC glossary at 5.
122 The actual frequency response is the increase
in output from generators after loss of a generator
and determines the frequency at which generation
and load come in balance again.
123 Staff Preliminary Assessment at 28–30.
124 For example, certain generating units such as
combined cycle units are not capable of increasing
their output to restore the frequency back to 60 Hz
and, in fact, their frequency responses tend to be
opposite of what is required and thus aggravate a
situation even further.

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and Western Interconnections have been
declining every year for the past
decade.125 NERC’s Frequency Response
White Paper discusses these issues in
detail.
167. Staff noted that BAL–003–0 does
not include Levels of Non-Compliance
and has only one Measure. Staff pointed
out limitations in the single Measure
contained in BAL–003–0, which
requires balancing authorities to
conduct frequency response surveys
only when NERC specifically requests
that such surveys be performed.
iii. Comments
168. NERC states that it is important
to distinguish between frequency bias
and frequency response. With regard to
the use of a frequency bias setting that
is different from actual frequency
response, NERC states that BAL–003–0
allows a balancing authority to set its
frequency bias setting to match its
actual frequency response. For some
balancing authorities that are unable to
calculate their frequency response
dynamically, BAL–003–0 establishes a
minimum of 1 percent of the balancing
authority’s peak demand to ensure
sufficient frequency response from its
generators. Southern states that the sum
of frequency bias setting for all of the
balancing authorities in the Eastern
Interconnection is 6,700 MW/0.1 Hz,
whereas the actual frequency response
is 2,800 MW/0.1 Hz. In sum, it claims
that the Eastern Interconnection is overbiased by a factor of 2.4 and the matter
of frequency bias setting should not be
taken lightly.
169. ReliabilityFirst agrees with staff
that use of an inappropriate frequency
bias setting may have an adverse impact
on reliability and adds that this should
be addressed by a team of experts.
ReliabilityFirst also states that the
Reliability Standard should include
Levels of Non-Compliance. It states that,
although the referenced surveys are
intended to monitor deviations in
frequency response, the survey should
be used more regularly. In addition,
ReliabilityFirst and CenterPoint state
that it is appropriate to allow balancing
authorities to continue to define their
own methodology for calculating
frequency bias setting.
170. Southern expresses concern
regarding staff’s statement that ‘‘the
frequency response of both the Eastern
and Western Interconnections has
decreased over the last 10 years’’ 126 and
asserts that the Eastern Interconnection
125 According to NERC’s Frequency Response
White Paper (dated April 6, 2004), the frequency
response in the Eastern Interconnection has
declined at a rate of 70 MW/0.1 Hz annually.
126 Staff Preliminary Assessment at 28.

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frequency bias setting is actually overbiased. In particular, Southern states
that the NERC Operating Committee
purposely chose to over-bias the
frequency bias setting of the
interconnections when it established the
1 percent floor and that the Eastern
Interconnection frequency bias setting is
currently over-biased by a factor of 2.4.
Southern believes that some
clarification and industry feedback may
be useful in considering issues and
concerns raised by staff with regard to
frequency bias and the way it is used to
maintain reliability.
iv. Commission Proposal
171. The Commission proposes to
approve BAL–003–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard as discussed
below.
172. NERC claims that BAL–003–0
allows a balancing authority to set its
frequency bias setting to match its
actual frequency response. Similarly,
NERC’s Petition describes the reliability
goal of BAL–003–0 is to: ‘‘maintain
interconnection frequency by * * *
ensuring that the balancing authority’s
frequency bias setting is appropriately
matched to its actual frequency
response (governor plus load
response).’’ However, Southern asserts
that the Eastern Interconnection is overbiased. The Commission agrees that the
frequency bias setting at peak, as
compared to the actual frequency
response of the system, is larger. The
Commission is concerned that overbiasing is an approach to compensate
for the low or no actual frequency
response from some balancing
authorities. In addition, Southern’s
assertion that the system is over-biased
is inconsistent with NERC’s stated
reliability goal and highlights staff’s
concern that data from actual events
suggest an overall decline in the actual
frequency response in the Eastern and
Western Interconnection.
173. In response to ReliabilityFirst
and CenterPoint, the Commission notes
that the Requirement R2 of BAL–003–0
allows balancing authorities to choose a
methodology for calculating frequency
bias setting from at least two different
ways. In addition, Requirement R2
requires that each balancing authority
shall establish its frequency bias setting
that is as close as practical to, or greater
than, its actual frequency response.
174. In addition, the Commission
notes that BAL–003–0 addresses
frequency response only during normal
conditions and does not establish the
frequency bias setting that will be
required during an emergency, black

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start or system restoration using
‘‘islanding’’ schemes. Without proper
frequency response, restoration of an
isolated area using black start generation
will be very difficult. Moreover,
‘‘islanding’’ schemes used in some areas
of the country may not be stable without
proper frequency response. The
Commission is aware that WECC is
addressing the need for proper
frequency response during all operating
conditions, including emergencies, and
that ERCOT has a procedure in place.127
175. Therefore, the Commission
invites comments whether BAL–003–0
appropriately addresses frequency bias
setting during normal as well as
emergency conditions and should a
requirement be added for balancing
authorities to calculate the frequency
response necessary for reliability in
each of the interconnections and
identify a method of obtaining that
frequency response from a combination
of generation and load resources.
176. Further, the surveys mentioned
in Measure M1 are only conducted
when NERC requests such surveys. The
Commission proposes that yearly
surveys should be performed to
compare the calculated frequency bias
values against actual frequency response
to refine the balancing authorities’
frequency bias setting. While the
Commission has identified concerns
with regard to BAL–003–0, we believe
that the Reliability Standard serves an
important purpose in ensuring that
balancing authorities accurately
calculate their frequency bias setting to
match their frequency response. While
we have proposed a number of
improvements to the Reliability
Standard, we nonetheless, believe that
the proposed Requirements set forth in
BAL–003–0 are sufficiently clear and
objective to provide guidance for
compliance.
177. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard BAL–003–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to BAL–003–0 that (1) includes Levels
127 See WECC’s Frequency Response Standard
White Paper (2005), at http://www.wecc.biz/
documents /library/RITF /FRR_White_Paper_
v12_1–27–06.pdf

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of Non-Compliance and (2) modifies
Measure M1 to include yearly surveys.
f. Time Error Correction (BAL–004–0)
i. NERC Proposal
178. The purpose of BAL–004–0 is to
ensure that time error corrections are
conducted in a manner that does not
adversely affect the reliability of the
Interconnection.128 The Reliability
Standard requires that: (1) Only a
reliability coordinator is eligible to serve
as time monitor and that the NERC
Operating Committee shall designate a
single reliability coordinator in each
Interconnection to serve as time monitor
for that Interconnection; (2) the time
monitor shall monitor time error and
initiate and terminate all corrective
action orders in accordance with the
North American Energy Standards
Board (NAESB) Time Error Correction
Procedure; (3) each balancing authority
shall participate in time error
corrections; and (4) any reliability
coordinator in an Interconnection may
request the time monitor to terminate a
time error correction for reliability
reasons, and that balancing authorities
may request termination of a time error
correction through their respective
reliability coordinator for reliability
reasons. The proposed Reliability
Standard would apply to reliability
coordinators and balancing authorities.
ii. Staff Preliminary Assessment
179. Staff noted that this Reliability
Standard does not contain any Measures
or Levels of Non-Compliance. Staff
highlighted the importance of
developing Measures to assure that each
balancing authority and reliability
coordinator participates in achieving
time error corrections since an analysis
of time error correction data available
on the ERO’s Web site indicates that
participation may be lacking.
iii. Comments
180. ReliabilityFirst agrees with staff
that BAL–004–0 lacks Measures and
Levels of Non-Compliance.
iv. Commission Proposal
181. Although Requirement R3
requires that all balancing authorities
participate in time error corrections,
data from the NERC time error Web page
indicates that the efficiency of the time
error correction has significantly
128 The NERC glossary defines ‘‘time error
correction’’ as ‘‘an offset to the Interconnection’s
scheduled frequency to return the Interconnection
Time Error to a predetermined value.’’ NERC
glossary at 14. Time error is caused by the
accumulation of frequency error over a given
period.

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decreased over the last 10 years.129 This
decrease in efficiency is an indication
that not all of the balancing authorities
are fully participating in time error
corrections. The Commission expects
the ERO will ensure compliance with
this Requirement.
182. In addition, the Commission
notes that WECC has implemented an
automatic time error correction
procedure 130 that, according to data on
the NERC Web site, is more effective in
minimizing both time error corrections
and inadvertent interchange.131
Although the WECC time error
correction procedure is not before us for
consideration, since the WECC
procedure appears more effective, the
Commission seeks comment whether it
should require that NERC adopt
Requirements similar to those in the
WECC automatic time error correction
procedure.
183. While the Commission has
identified concerns with regard to BAL–
004–0, we believe that the Reliability
Standard serves an important purpose
in ensuring that time error corrections
are conducted in a manner that does not
adversely affect the reliability of the
Interconnection. NERC should include
Levels of Non-Compliance and
additional Measures. Nonetheless, the
proposed Requirements set forth in
BAL–004–0 are sufficiently clear and
objective to provide guidance for
compliance.
184. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard BAL–004–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to BAL–004–0 that includes Levels of
Non-Compliance and additional
Measures. Further, as discussed above,
the Commission seeks comment
whether it should require that NERC
adopt Requirements similar to those in
129 NERC, Time Error Reports, at http://
www.nerc.com/~filez/∼timerror.html. Yearly data
for total efficiency was 117 percent for 1996 and 65
percent for 2005. If there is more participation than
needed, the efficiency can be greater than 100
percent. The goal is to be near 100 percent.
130 See http://www.wecc.biz/documents/library/
procedures/Time_Error_ Procedure_10–04–02.pdf.
131 See http://www.nerc.com/~filez/∼inadv.html
(regarding inadvertent interchange data) and
http://www.nerc.com/~filez/∼timerror.html
(regarding time error correction).

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the WECC automatic time error
correction standard.
g. Automatic Generation Control (BAL–
005–0)
i. NERC Proposal
185. The reliability goal of this
Reliability Standard is to maintain
Interconnection frequency by requiring
that all generation, transmission, and
customer load be within the metered
boundaries of a balancing authority
area, and establishing the functional
requirements for the balancing
authority’s regulation service, including
its calculation of ACE. BAL–005–0
requires that: (1) All generation,
transmission, and load operating within
an Interconnection must be included
within the metered boundaries of a
balancing authority area; (2) each
balancing authority shall maintain
regulating reserve to meet the control
performance standard; and (3) adequate
metering, communication and control
equipment are employed in the
provision of regulation service. In
addition, the Reliability Standard
includes a series of requirements
pertaining to the operation of automatic
generation control and a series of
requirements pertaining to the
calculation of ACE. The proposed
Reliability Standard would apply to
balancing authorities, generator
operators, transmission operators, and
load serving entities.
ii. Staff Preliminary Assessment
186. Staff stated that this Reliability
Standard does not require a generation
operator or load-serving entity to
provide automatic generation control
capabilities to its balancing authority.
Nor does it require the calculation of the
amount of automatic generation control
the generation operators or load-serving
entities must have at all times. Without
these requirements, it is not possible to
determine whether there are adequate
resources to maintain system frequency
close to 60 Hz. Staff also noted that this
Reliability Standard does not contain
Measures or Levels of Non-Compliance.

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iii. Comments
187. ReliabilityFirst agrees with Staff
that Measures and Levels of NonCompliance need to be added to this
Reliability Standard.
188. CPUC expresses concern
regarding a statement in the Staff
Preliminary Assessment that BAL–005–
0 does not require generator operators or
load-serving entities to provide
automatic generation control
capabilities to the balancing

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authority.132 It suggests that, in lieu of
requiring generators to provide
automatic generation control units,
balancing authorities should have a
specified percentage of their load
subject to automatic generation control.
CPUC also states that the characteristics
of the load in the area and the amount
of generation that is responsive to
changes in voltage and frequency
should also be considered.
189. LPPC states that Requirement
R17, which provides that each balancing
authority must periodically calibrate its
time error and frequency devices,
should be moved to a ‘‘facility’’ (FAC)
Reliability Standard and should also
apply to the transmission operations
and reliability coordinators. LPPC states
that balancing authorities do not have
time error devices and the reliability
coordinator is responsible for
monitoring time error. It also states that
the requirement to calibrate time error
devices should be deleted.
iv. Commission Proposal
190. The Commission proposes to
approve Reliability Standard BAL–005–
0 as mandatory and enforceable. In
addition, we propose to direct that
NERC modify the Reliability Standard to
address the Commission’s concerns
discussed below.
191. Currently, the title of the
Reliability Standard implies that only
generators can participate in regulation
control portion of contingency reserves.
The title should be changed from
Automatic Generation Control to clearly
indicate that it includes the systems
necessary to implement Demand Side
Management and Direct Control Load
Management as part of contingency
reserves and not just conventional
generation.
192. The stated goal of this Reliability
Standard is to assure that all generation
and load is under the control of a
balancing authority. Ideally, the
balancing authority would have control
over adequate amounts and types of
generation reserves and controllable
load management resources under all
operating conditions and at all times.133
The Commission notes that
Requirement R2 of BAL–005–0 requires
a balancing authority to obtain sufficient
regulating reserves controlled by
automatic generation control to meet the
132 Staff

Preliminary Assessment at 32.
Resources Subcommittee (Frequency
Task Force), Frequency Response Standard
Whitepaper (2004), at http://www.nerc.com/pub/
sys/all_updl/oc/rs/
Frequency_Response_White_Paper.pdf. See also
WECC Reserve Issues Task Force, Frequency
Response Standard White Paper (2005), at http://
www.wecc.biz/documents/library/RITF/
FRR_White_Paper_v12_1–27–06.pdf.
133 NERC

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CPS requirements of BAL–001–0.
However, the balancing authority may
not itself have generation or control over
loads that are the sources of regulating
reserves. In contrast, a generation
operator or load-serving entity typically
has (or could have) the facilities to
provide automatic generation control
capabilities to the balancing authority.
Recognizing that insufficient automatic
generation control would constitute a
violation of this Reliability Standard,
the Commission is interested in
understanding if any balancing
authority is experiencing or is
predicting any difficulty in obtaining
sufficient automatic generation control.
193. With regard to CPUC’s concern,
the Commission does not propose a
requirement that all generators provide
automatic generation control
capabilities. The Commission
recognizes that, due to unit
characteristics or operating restrictions,
certain types of resources may not be
capable of operation with automatic
generation control, or automatic
generation control may not be
economically feasible. With regard to
CPUC’s suggestion that the Reliability
Standard require a balancing authority
to have a certain percentage of its load
subject to automatic generation control,
the Commission notes that this may be
one method of determining the amount
of regulating reserve necessary to meet
Requirement R2.
194. The Commission notes that there
are frequency excursions without loss of
generation on a regular basis. Also,
significant frequency excursions,
without loss of generation are becoming
more frequent.134 The Commission
proposes that BAL–005–0 include a
Requirement that addresses the amount
of automatic generation control a
balancing authority must have, prior to
a contingency, to ensure that load
variations and changes in schedules can
be accommodated without frequency
deviations beyond an appropriate
threshold.
195. Requirement R17 requires
balancing authorities to calibrate time
error and frequency devices annually
according to the accuracy levels detailed
in the Reliability Standard. The
Commission disagrees with LPPC that
the reference to the calibration of time
error devices should be removed from
Requirement R17 of this Reliability
Standard. The Commission prefers that
Requirements intended to achieve a
specific reliability goal be in the same
Reliability Standard or group of
Reliability Standards. Since the BAL
134 See PJM RTO White Paper, Frequency
Excursions, by Koza, Williams and Herbsleb.

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group of Reliability Standards contains
reliability goals concerning frequency,
the Commission believes that
Requirement R17 is appropriately
placed in BAL–005–0.
196. While we have identified
concerns with regard to BAL–005–0, we
believe that the proposal serves an
important purpose in ensuring that the
functional requirements of a balancing
authority’s regulation service are met.
The Commission believes it is important
that NERC include Measures, including
a Measure that would provide for
verification of minimum automatic
generation control or regulating
reserves, and Levels of NonCompliance. Nonetheless, the proposed
Requirements set forth in BAL–005–0
are sufficiently clear and objective to
provide guidance for compliance.
197. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard BAL–005–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to BAL–005–0 that: (1) Includes
Requirements that identify the
minimum amount of automatic
generation control or regulating reserves
a balancing authority must have at any
given time; (2) changes the title of the
Reliability Standard to be neutral as to
source of the reserves; (3) includes DSM
and Direct Control Load Management as
part of contingency reserves; and (4)
includes Levels of Non-Compliance and
Measures, including a Measure that
provides for a verification process over
the minimum required automatic
generation control or regulating reserves
a balancing authority maintains.
h. Inadvertent Interchange (BAL–006–1)

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i. NERC Proposal
198. BAL–006–1135 requires that: (1)
Each balancing authority calculate and
record inadvertent interchange on an
hourly basis; (2) all AC tie lines with
adjacent balancing authority areas be
included in a balancing authority’s
inadvertent account, and the balancing
authority take into account interchange
135 On August 28, 2006, NERC submitted BAL–
006–1 for approval, which replaces BAL–006–0.
BAL–006–1 is the same as BAL–006–0 except that
it includes a regional difference for SPP under an
urgent action procedure. The comments submitted
in response to the Staff Preliminary Assessment on
BAL–006–0 apply equally to BAL–006–1.

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from jointly-owned generation; (3) all
Interconnection points be equipped
with common megawatt-hour meters
with readings provided to adjacent
balancing authorities; (4) adjacent
balancing authorities compute and
record inadvertent interchange on an
hourly basis using common net
scheduled interchange and net actual
interchange values, and use the agreedto data to compile their monthly
accumulated inadvertent interchange;
and (5) balancing authorities make after
the fact corrections to the agreed-to
inadvertent amount as needed to reflect
actual operating conditions. The
proposed Reliability Standard would
apply to balancing authorities.
199. This Reliability Standard does
not contain Measures but does contain
a compliance monitoring process which
requires a balancing authority to submit
monthly inadvertent interchange reports
to its regional reliability organization.
The regional reliability organization is
then required to submit a monthly
inadvertent interchange summary for its
region to NERC. This Reliability
Standard contains one Level of NonCompliance which states that if a
balancing authority does not timely
submit its inadvertent interchange
report to the regional reliability
organization, it shall be considered noncompliant.
ii. Staff Preliminary Assessment
200. Staff found that this Reliability
Standard does not contain any
Requirement that would prevent a
balancing authority from excessively
depending on other balancing
authorities over time. This makes it
possible for balancing areas to lean on
other balancing areas and not settle their
inadvertent accounts on a timely basis.
Data available from the NERC Web site
indicates that the magnitudes of
inadvertent interchange for some
regional reliability organizations in the
Eastern Interconnection are
increasing.136
201. Staff also noted that this standard
does not contain Measures and contains
a single Level of Non-Compliance which
is only associated with a Requirement
for submission of a monthly report on
inadvertent interchange.
iii. Comments
202. NERC contends that inadvertent
imbalances do not affect the real-time
operations of the Bulk-Power System.
Rather, they represent accumulation of
the real-time imbalances over hours,
days and weeks. A separate NAESB
standard, referred to as ‘‘Inadvertent
136 See

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Interchange Payback Standard—WEQ–
007’’ deals with how balancing
authorities should eliminate their
inadvertent interchanges. According to
NERC, real-time imbalances between the
generation and load are appropriately
dealt with in BAL–001–0 and BAL–002–
0.
203. TAPS argues that the treatment
afforded to balancing authorities under
NERC’s proposed Reliability Standards
and NAESB rules is not comparable to
the treatment afforded to non-controlarea utilities under the Commission’s
OATT. In particular, TAPS states that,
under the NERC standards, no penalties
are assessed on a balancing authority for
inadvertent interchange whereas under
the OATT, penalties are assessed on
non-control-area utilities for energy
imbalances. TAPS is concerned that the
OATT Reform NOPR does not
adequately address the disparate
treatment of imbalances.
204. ReliabilityFirst agrees with staff
that requirements should be added to
prevent balancing authorities from
depending excessively on other
balancing authorities.
205. LPPC states that Requirement R2
of BAL–006–0, which provides that
each balancing authority shall include
all AC tie lines that connect to its
adjacent balancing authority areas in its
inadvertent interchange account, should
apply to ‘‘physical’’ adjacent balancing
authorities. It explains that the NERC
glossary explains that an ‘‘adjacent
balancing authority’’ is interconnected
to another balancing authority either
directly or via a multi-party agreement
or transmission tariff. Thus, according
to LPPC, the meaning of this
Requirement changed when the word
‘‘physical’’ was removed during the
conversion to the Version 0 standards.
LPPC also contends that Requirements
R4.1, R4.1.1, R4.1.2, R4.2, R4.3, and R5
are after-the-fact energy accounting
practices and should be incorporated
into the NAESB business practices.
LPPC also suggests that Requirement R3
of BAL–006 is redundant with
Requirement R12.1 in BAL–005–0.
iv. Commission Proposal
206. The Commission proposes to
approve Reliability Standard BAL–006–
1 as mandatory and enforceable. In
addition, we propose to direct that
NERC modify the Reliability Standard to
address the Commission’s concerns
discussed below.
207. The Commission agrees with
NERC that inadvertent imbalances do
not affect the real-time operations of the
Bulk-Power System. While large
inadvertent imbalances pose no
immediate threat to grid reliability, they

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represent dependence by some
balancing authorities on their neighbors.
The Commission notes that WECC has
placed a limit on the inadvertent
accumulation based on the bias of the
balancing authority. We invite
comments as to whether accumulation
of large amount of inadvertent
imbalances is a concern to the industry
and if so, options to address the
accumulation.
208. With respect to TAPS concerns
regarding disparate treatment of
imbalances for non-control area utilities,
the Commission is addressing this issue
in the OATT Reform NOPR, and TAPS
should pursue its concerns in that
proceeding. Moreover, the issues raised
by TAPS do not impact reliability of the
Bulk-Power System, but instead are
economic in nature.
209. We disagree with LPPC’s
comment that Requirement R2 should
be applicable only to ‘‘physical’’
adjacent balancing authorities because it
is reasonable to include those balancing
authorities that are not physically
adjacent but are connected by a multiparty agreement or transmission tariff.
210. With regard to LPPC’s comment
that several of the Requirements should
be incorporated into NAESB business
practices, the Commission notes that
there is currently an industry process in
place between NERC and NAESB to
determine which standards or portions
of standards should be developed as
business practices. The Commission
prefers to use that process to resolve
issues with the particular Requirements
highlighted by LPPC. With respect to
LPPC’s comment that Requirement R3 of
BAL–006–0 is redundant with
Requirement R12.1 in BAL–005–0, the
Commission observes that the two
Requirements, although worded
somewhat differently, are very similar.
We propose to require NERC to review
these Requirements and remove any
unnecessary duplication.
211. As mentioned above, the
Reliability Standard includes a single
Level of Non-Compliance that is
triggered if a balancing authority fails to
report its inadvertent interchange on
time. There are no specific Measures
concerning the accumulation of large
inadvertent imbalances. Nor are there
Measures and Levels of NonCompliance associated with each of the
Requirements. While the Commission
has identified concerns with regard to
BAL–006–1, we believe that the
proposal serves an important purpose in
defining a process to ensure that
balancing areas do not excessively
depend on other balancing areas in the
Interconnection for meeting their
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Commission believes that it is important
for NERC to provide Measures and
additional Levels of Non-Compliance.
Nonetheless, the proposed
Requirements set forth in BAL–006–1
are sufficiently clear and objective to
provide guidance for compliance.
212. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard BAL–006–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to BAL–006–1 that adds Measures and
additional Levels of Non-Compliance
including Measures concerning the
accumulation of large inadvertent
imbalances.
i. Regional Differences to BAL–006–1:
Inadvertent Interchange Accounting and
Financial Inadvertent Settlement
i. NERC Petition
213. BAL–006–1 provides for two
regional differences. First, NERC
explains that a regional difference is
needed for an RTO with multiple
balancing authorities. The control area
participants of MISO requested that
MISO be given an Inadvertent
Interchange account so that financial
settlement of all energy receipts and
deliveries using LMP could be
implemented to meet their Commission
directed market obligations.
Subsequently, Southwest Power Pool
(SPP) requested, and NERC approved,
that the same regional difference apply
to SPP as well.137
214. Second, a regional difference
would apply to the control area
participants of MISO and SPP that
would allow the RTO to financially
settle inadvertent energy between
control areas in the RTO. Each RTO
would maintain accumulations of the
net inadvertent interchange for all the
control areas in the RTO after the
financial settlement and as such would
not affect the accumulation of netinterchange by non-participant control
areas.
ii. Comments
215. These regional differences were
not addressed in the Staff Preliminary
Assessment and, consequently, no
comments were received.
137 BAL–006–1, filed on August 28, 2006, would
extend the regional difference to SPP.

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iii. Commission Proposal
216. The two proposed regional
differences relate solely to facilitating
financial settlements of accumulated
inadvertent interchange and have
minimal, if any, reliability implications.
These regional differences allow
coordination with the current RTO
market tariffs and promote incentives
that would deter balancing authorities
from depending excessively on other
balancing authorities. Accordingly, the
Commission proposes to approve these
regional differences.
2. CIP: Critical Infrastructure Protection
a. Overview
217. The Critical Infrastructure
Protection group of Reliability
Standards, as filed, consists of two
standards aimed at reporting
occurrences of sabotage to the proper
authorities and establishing security for
critical cyber assets. The first standard
is CIP–001–0 (Sabotage Reporting). The
second standard is Urgent Action 1200
(UA–1200), which addresses the cyber
security of bulk electric system assets.
UA–1200 was filed by NERC for
informational purposes only and is
therefore not the subject of Commission
action in this proposed rule.
b. NERC Proposal
218. CIP–001–0 requires that each
reliability coordinator, balancing
authority, transmission operator,
generation operator and load-serving
entity: (1) Have procedures for
recognizing and for making their
operating personnel aware of sabotage
events; (2) have procedures for
communicating information concerning
sabotage events to appropriate ‘‘parties’’
in the interconnection; (3) provide
operating personnel with guidelines for
reporting disturbances due to sabotage
events; and (4) establish
communications contacts with
applicable government officials and
develop appropriate reporting
procedures. The reliability goal of the
standard is to ensure that operating
entities recognize sabotage events and
inform appropriate authorities and each
other to properly respond to the
sabotage (via cyber or physical means)
to minimize the impact on the BulkPower System.
c. Staff Preliminary Assessment
219. Staff noted that CIP–001–0 does
not require an entity to actually contact
a governmental or regulatory body in
the event of sabotage (though staff
acknowledged that Standard EOP–004–
0 does contain such a requirement).
Staff also found that there is no

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definition of ‘‘sabotage’’ in the
Reliability Standard, which could lead
to inconsistent application. Finally, staff
stated that CIP–001–0 does not contain
Measures or Levels of Non-Compliance.
d. Comments
220. In response to the Staff
Preliminary Assessment, NERC
comments that a requirement for
reporting to government agencies is a
matter of jurisdiction of the respective
government agencies and not one of
reliability. NERC states that it will
consider developing a definition of
sabotage, though it believes there is no
confusion within industry regarding the
meaning of ‘‘sabotage’’ in CIP–001–0.
221. ReliabilityFirst comments that
language in CIP–001–0 is ambiguous but
does not identify any specific examples.
It states that CIP–001–0 is a ‘‘Version 0’’
standard, which means that it was not
developed using NERC’s ANSIaccredited standards development
process. ReliabilityFirst further
comments that, during the development
process for standards CIP–002 through
CIP–009, the drafting team generally
considered that standard CIP–001–0
dealt only with physical sabotage
reporting and, therefore, addressed
cyber incident reporting requirements in
CIP–008.
222. With regard to the lack of
metrics, CenterPoint observes that
metrics would be difficult to develop.138

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e. Commission Proposal
223. The Commission proposes to
approve CIP–001–0 as mandatory and
enforceable. In addition, we propose
directing that NERC develop
modifications to the Reliability
Standard, as discussed below.
224. Order No. 672 explained that one
of the factors that the Commission
considers when reviewing a proposed
Reliability Standard is whether the
proposal is clear and unambiguous.139
The Requirements of CIP–001–0 refer to
a ‘‘sabotage event’’ but do not define
that term. Generally, we believe that
‘‘sabotage’’ is a commonly understood
term 140 and the Requirements of CIP–
138 Many commenters address concerns that staff
raised with UA–1200. Those comments ran the
gamut from support to disagreement with the Staff
Preliminary Assessment. Since UA–1200 was
submitted for informational purposes only, we will
not address this Reliability Standard or related
comments in the NOPR.
139 Order No. 672 at P 325
140 The American Heritage Dictionary defines
‘‘sabotage’’ as ‘‘1. Destruction of property or
obstruction of normal operations, as by civilians or
enemy agents in time of war. 2. Treacherous action
to defeat or hinder a cause or an endeavor;
deliberate subversion.’’ The American Heritage
Dictionary of the English Language, (Houghton
Mifflin Co., 4th Ed. 2000).

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001–0 are enforceable. While the
common understanding of the term
sabotage should suffice in most
circumstances, we are concerned that
situations may arise in which it is not
clear whether action pursuant to CIP–
001–0 is required. For example, a breakin that gains access to a control room
but does not cause damage, or a
physical attack that results in minor
damage, may be reported as sabotage by
one entity but not another. Thus, the
ERO should provide guidance clarifying
the triggering event for an entity to take
action pursuant to CIP–001–0.
225. CIP–001–0 requires that an
applicable entity have procedures for
recognizing sabotage events and making
its operating personnel aware of
sabotage events. However, it does not
establish baseline requirements
regarding what issues should be
addressed by the developed procedures.
For example, a procedure could identify
a chronological ‘‘checklist’’ of minimum
actions that would apply if a sabotage
event occurs, such as the timing and
chain of communication, the
preservation of evidence, repairing
damage and contacting the appropriate
law enforcement officials.
226. As stated above, while an
applicable entity must establish
communication contacts, there is no
Requirement in CIP–001–0 that an
applicable entity actually contact the
appropriate governmental or regulatory
body in the event of sabotage consistent
with the purpose of the standard, which
states that ‘‘[d]isturbances or unusual
occurrences, suspected or determined to
be caused by sabotage, shall be reported
to the appropriate systems,
governmental agencies, and regulatory
bodies.’’ 141 We believe that mandatory
reporting of a sabotage event is
important to achieve the reliability goal
of this proposed Reliability Standard.
Further, since sabotage is an intentional
action directed at a specific entity, the
timely reporting of such events is of the
utmost importance as a tool to warn
other entities of potential problems.
227. With regard to NERC’s
comments, NERC has not adequately
explained its statement that reporting of
sabotage is an issue of jurisdiction
instead of reliability. It may be
necessary for NERC to lay the
groundwork with the appropriate
government agencies, such as the
Federal Bureau of Investigation or
Department of Homeland Security, on
an appropriate protocol for a report of

sabotage. For example, NERC may want
to consider the requirements for timely
reporting developed by the Department
of Homeland Security found in the
Electric Sector Information Sharing &
Analysis Center (ESISAC) Indications,
Analysis and Warning Program (IAW)
Standard Operating Procedure (SOP).142
Accordingly, the Commission proposes
to direct NERC to modify the Reliability
Standard to require an applicable entity
to contact appropriate federal
authorities, such as the Department of
Homeland Security, in the event of
sabotage within a specified period of
time.
228. The Commission is further
concerned that CIP–001–0 does not
include a requirement for the periodic
review or updating of sabotage reporting
plans or procedures, or for the periodic
testing of the sabotage reporting
procedures to verify that they achieve
the desired result. The Commission
believes that a periodic review is
appropriate because appropriate
methods of responding to a sabotage
event may change or become more
sophisticated. Also, contacts for
reporting an incident should be
periodically updated.
229. As mentioned above, CIP–001–0
does not contain Measures or Levels of
Non-Compliance. Though CenterPoint
believes that compliance elements
would be difficult to develop, the
Commission believes that Measures and
Levels of Non-Compliance are important
in this Reliability Standard to assure the
consequences of failure to comply with
the requirements are clear and
unambiguous.
230. While the Commission has
identified concerns with regard to CIP–
001–0, we believe that the proposal
serves an important purpose in ensuring
that operating entities properly respond
to sabotage events to minimize the
adverse impact on the Bulk-Power
System. The Commission believes that it
is important for NERC to provide
Measures and Levels of NonCompliance for this proposed Reliability
Standard, and that a definition of
‘‘sabotage’’ will provide desired clarity.
Nonetheless, the proposed
Requirements set forth in CIP–001–0 are
sufficiently clear and objective to
provide guidance for compliance.
231. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission

141 Reference in CIP–001–0 to Standard EOP–
004–0, which requires entities to report actual or
suspected physical or cyber attacks to the U.S.
Department of Energy Operations Center would
improve CIP–001–0.

142 ESISAC IAW SOP requires a preliminary
report to be filed within 60 minutes, a follow-up
report to be filed within four to six hours after the
preliminary report and a final report to be filed
within 60 days.

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by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard CIP–001–0
as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to CIP–001–0 that: (1) Includes
Measures and Levels of NonCompliance; (2) gives guidance for the
term ‘‘sabotage’’; (3) requires an
applicable entity to contact appropriate
Federal authorities, such as the
Department of Homeland Security, in
the event of sabotage within a specified
period of time; and (4) requires periodic
review of sabotage response procedures.
3. COM: Communications
a. Introduction
232. The Communications group
contains two Reliability Standards. The
first Reliability Standard requires that
transmission operators, balancing
authorities and other applicable entities
have adequate internal and external
telecommunications facilities for the
exchange of interconnection and
operating information necessary to
maintain reliability. The second
Reliability Standard requires that these
communication facilities be staffed and
available for addressing real-time
emergencies and that operating
personnel carry out effective
communications.

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General Issues
Performance Metrics
233. CenterPoint comments that
‘‘some or all’’ of the Communication
group of Reliability Standards should be
replaced by establishing performance
metrics. It suggests that the Commission
refer these Reliability Standards back to
NERC with a directive to explore
replacing process-oriented requirements
with performance metrics. CenterPoint
points to ERCOT as an example of a
region that is developing performance
metrics for telemetry and
telecommunication infrastructure
necessary to ensure situational
awareness and address commercial
considerations associated with a
planned transition to a nodal market
design.
234. The Commission believes that
including performance metrics within a
Reliability Standard in specific
instances would be an improvement.
However, we do not see the
development of performance metrics,
lagging and/or forward-looking, as an
adequate substitute for a mandatory and
enforceable Reliability Standard.

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235. Accordingly, while the
Commission encourages the use of
performance metrics in conjunction
with Measures and Requirements, we
reject CenterPoint’s suggestion that the
proposed Communications Reliability
Standards be replaced with performance
metrics.
Local Control Centers
236. The terms transmission operator
and generator operator in NERC’s
functional model include the activities
that those operators would perform to
achieve their specific reliability goals.
As identified by MISO and Allegheny,
confusion can arise when using these
terms in the context of an ISO or RTO
or in any organization that pools
resources. In such organizations,
decision making and implementation
are performed by separate groups. The
decision-making portion of the
transmission operator and, to a lesser
extent, the generation operator function
typically is completed by the ISO or
RTO. The actual implementation is
performed by either local transmission
control centers or independent
generation control centers. For example,
the transmission and generation owners
usually operate and maintain the
individual facilities, control systems,
SCADA systems, etc. The data from
these locations are sent to the ISO or
RTO control center either directly or
through the entity’s local control center.
Upon receipt, the operators in the ISO
or RTO control center make decisions
that are transmitted to the local
transmission and generation control
centers. In some ISO or RTO
arrangements, the request for action may
be further divided and sent to
individual generation facilities or
transmission switching stations where it
is actually implemented.
237. The Commission proposes that
all control centers and organizations
that are necessary for the actual
implementation of the decisions or are
needed for operation and maintenance
made by the ISO or RTO or the pooled
resource organizations are part of the
transmission or generation operator
function in the functional model. All of
the requirements for telecommunication
would apply to all of these entities as
appropriate to their respective functions
within the transmission or generation
operation functional model. Further, we
note that this proposed definition of
responsibility within a function would
apply to other Reliability Standards that
address such activities as training,
operator certification, transmission
operations, and cyber and physical
security.

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b. Telecommunications (COM–001–0)
i. NERC Proposal
238. NERC states that COM–001–0
ensures coordinated
telecommunications among operating
entities, which is fundamental to
maintaining grid reliability. This
proposed Reliability Standard
establishes general telecommunications
requirements for specific operating
entities, including equipment testing
and coordination. It also establishes
English as the common language
between and among operating
personnel, and sets policy for using the
NERCNet telecommunications system.
COM–001–0 applies to transmission
operators, balancing authorities,
reliability coordinators and NERCNet
user organizations.
239. NERC indicates that it will
modify this proposed Reliability
Standard to address the lack of
Measures and Levels of NonCompliance and resubmit the proposal
for Commission approval in November
2006.
ii. Staff Preliminary Assessment
240. The Staff Preliminary
Assessment pointed out that the COM–
001–0 contains a general requirement to
provide ‘‘adequate and reliable’’
telecommunications facilities for all
applicable operating entities, but does
not provide specific or minimum
requirements on adequacy, redundancy
and diverse routing of the
telecommunications facilities necessary
to ensure the exchange of operating
information, both internally and among
the operating entities.143
241. Staff also indicated that the
Requirements set forth in the proposed
Reliability Standard do not differentiate
between operating entities with
different needs. Staff explained that, for
example, reliability coordinators need
telecommunication facilities beyond
those required by other operating
entities. In addition, staff noted that
generator operator is not designated as
an applicable entity.
iii. Comments
242. NERC states with respect to
Blackout Report Recommendation No.
26, which called for a tightening of its
communications protocols and
upgrading its communication hardware,
that it has installed a new conference
bridge, approved a new set of hotline
procedures for reliability coordinator
hotline calls and is working on an
upgrade of its Reliability Coordinator
Information System that provides real143 Staff

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time information to reliability
coordinator control areas. NERC also
states that it is not aware of any
operating problems this Reliability
Standard is causing. It explains that the
methods chosen by operating entities to
provide adequate and reliable
communications facilities ‘‘will drive
their needs for backup communications
facilities and communications circuits
with diverse routing.’’ 144
243. MRO generally agrees with staff’s
assessment of COM–001–0 and suggests
that the Reliability Standard be
reviewed and modified in its entirety. It
believes the Reliability Standard must
balance the capability that the
telecommunications industry can
realistically provide against what is
needed for reliability. MRO provides an
example of a situation where an electric
utility makes a good faith effort to
comply with a dual communication
path mandate by contracting with a
third party vendor without knowing that
this path contains a single point of
failure for both communication paths.
244. ReliabilityFirst comments on the
need for expedited development of
missing Measures and Levels of NonCompliance.
iv. Commission Proposal
245. The Commission proposes to
approve Reliability Standard COM–001–
0 as mandatory and enforceable. In
addition, we propose to direct that
NERC develop modifications to the
Reliability Standard, as discussed
below.
246. With regard to MRO’s concern
about redundancy, we believe that the
Reliability Standard is sufficiently clear
that the functional entity is responsible
for achieving redundancy and diverse
routing requirements.
247. The Staff Preliminary
Assessment expressed concern that
COM–001–0 does not provide specific
or minimum requirements on adequacy,
redundancy and diverse routing of the
telecommunications facilities necessary
to ensure the exchange of operating
information. While MRO concurs with
staff, NERC suggests that the methods
chosen to comply with COM–001–0 will
‘‘drive’’ the applicable entities’ need for
redundant telecommunication facilities
and diversely routed telecommunication
circuits. The Commission believes that
the Reliability Standard might be
improved if NERC was to provide
specific or minimum requirements for
adequacy, redundancy and diverse
routing. At the same time, we are
concerned that the addition of specific
or minimum requirements may result in
144 NERC

Comments at 118.

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a Reliability Standard that reduces the
flexibility of applicable entities in
achieving compliance or implementing
new technologies and motivates
applicable entities to simply achieve
compliance with the minimum
requirement. Accordingly, we seek
comment on the specific requirements
or performance criteria for
telecommunications facilities.145
248. Further, assuming we direct
NERC to develop such specific
requirements, the Commission also
seeks comment whether the modified
Reliability Standard should provide
requirements that also consider the
relative role of applicable entities.
While the Commission believes that
applicable entities of all roles should
have adequate telecommunications
equipment, the needs will likely vary
based on role. We would expect a
modification to COM–001–0, if directed,
to develop sufficient information so that
transmission owners and other
applicable entities of all sizes will have
some specific guidance as to what is
required to maintain an acceptable
telecommunications facility.
249. The Commission notes that this
Reliability Standard is applicable to
transmission operators, balancing
authorities, reliability coordinators, and
NERCNet user organizations. However,
during normal and emergency
operations, communications with
additional entities are required. For
example, during a blackstart when
normal communications may be
disrupted, it is essential that the
transmission operator, balancing
authority, and reliability coordinator
have communications with the
generator operators and distribution
providers. The Commission proposes
that NERC modify the applicability
section of COM–001–0 to make
generator operators and distribution
providers as applicable entities and
modify the requirements of this
Reliability Standard as necessary to
account for this change.
250. Telecommunication facilities for
emergency operations including
restoration require special provisions
which are lacking in COM–001–0.
Inadequate telecommunication facilities
during emergency operations would
aggravate the duration and extent of the
emergency and delay the subsequent
restoration. Periodic testing of
telecommunication facilities will insure
that these facilities are functional when
required. Accordingly, the Commission
145 Loss of data from some entities may result in
errors or non convergence of state estimators and
security analysis, which may result in loss of a wide
area view, situational awareness, and economic
information such as LMP.

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proposes to direct NERC to modify
COM–001–0 to include requirements for
communication facilities for use during
emergency situations and periodic
testing of these facilities.
251. While the Commission has
identified a number of concerns with
regard to COM–001–0, this proposed
Reliability Standard serves an important
purpose by requiring transmission
operators and others to have necessary
telecommunication equipment. Further,
NERC should provide Measures and
Levels of Non-Compliance for this
proposed Reliability Standard.
Nonetheless, the Requirements set forth
in COM–001–0 are sufficiently clear and
objective to provide guidance for
compliance.
252. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard COM–001–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to COM–
001–0 that: (1) Includes Measures and
Levels of Non-Compliance; (2) includes
generator operators and distribution
provider as applicable entities; and (3)
includes requirements for
communication facilities for use during
emergency situations.
c. Communications and Coordination
(COM–002–1)
i. NERC Proposal
253. The stated purpose of COM–002–
1 is to ensure that transmission
operators, generator operators and
balancing authorities have adequate
communications and that their
communications capabilities are staffed
and available to address real-time
emergency conditions. This Reliability
Standard requires balancing authority
and transmission operators to notify
others through pre-determined
communication paths of any condition
that could threaten the reliability of its
area or when firm load shedding is
anticipated. NERC has indicated that it
will modify this Reliability Standard to
address the lack of Measures and Levels
of Non-Compliance and resubmit it for
Commission approval in November
2006.
ii. Staff Preliminary Assessment
254. Staff explained that COM–002–1
does not require that ‘‘the appropriate

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operating actions in normal and
emergency operating conditions that
may have reliability impact beyond a
local area or Reliability Coordinator’s
area * * * be assessed and approved by
the Reliability Coordinator, before being
implemented by the operating
entities.’’ 146 Staff noted that Blackout
Report Recommendation No. 26 calls for
effective communications, but COM–
002–1 does not provide for ‘‘tightened
communication protocols.’’

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iii. Comments
255. NERC agrees with the need to
develop additional Reliability Standards
addressing consistent communications
protocols among personnel responsible
for the reliability of the Bulk-Power
System. However, NERC does not
believe that ‘‘tightened communication
protocols’’ required by the Blackout
Report should include the requirement
that operating actions in normal and
emergency conditions must be assessed
and approved by the reliability
coordinator before being implemented
by the operating entities. Other
Reliability Standards require
coordination and communications
among all operating entities, and
transmission operators and balancing
authorities have adequate authority to
restore imbalances and mitigate
transmission (SOL and IROL) violations.
256. National Grid agrees with the
Staff Preliminary Assessment that
tighter communications protocols are
needed with respect to assessment and
approval of operating actions under
normal and emergency conditions, but it
believes any new requirements belong
in COM–002–1, which deals with
coordination rather than COM–001–0,
which sets forth requirements for
telecommunication facilities. National
Grid states that this Reliability Standard
for communication protocols should not
be intermixed with Reliability
Standards for communication facilities.
257. ReliabilityFirst and MRO
maintain that, without specific
Measures and Levels of NonCompliance, NERC will not be able to
implement consistent and effective
enforcement of COM–002–1. MRO states
that the Reliability Standard should
clarify the role of the Regional Entities
and clarify any distinctions between
COM–001–0 and COM–002–1.
iv. Commission Proposal
258. COM–002–1 requires
communications with the reliability
coordinator through predetermined
paths when a condition could threaten
‘‘the reliability of [the reliability

coordinator’s] area.’’ 147 As noted above,
several commenters are of the opinion
that this Reliability Standard does not
recognize that operating actions can
have reliability impacts beyond the
local area for which a particular
reliability coordinator is responsible.
NERC disagrees on this issue and points
out that other Reliability Standards
require coordination and
communications among operating
entities. However, the Reliability
Standards to which NERC refers require
such coordination and communications
only in limited, specified
circumstances. Further, while NERC
states that other Reliability Standards
require coordination and
communications among all operating
entities, the Commission notes that
transmission operators have unilateral
authority to mitigate transmission (SOL
and IROL) violations within their
jurisdictions. Thus, those entities can
take actions that place others at risk
because they do not have a wide area
view. Accordingly, we propose directing
NERC to add a Requirement that the
reliability coordinator assess and
approve actions that have impacts
beyond the area views of transmission
operators and balancing authorities.
259. In addition, we also believe that
tightened protocols are necessary. The
Blackout Report identifies ineffective
communication as one of the common
factors among major cascading
outages.148 The Commission recognizes
NERC for its efforts in following up on
Blackout Report Recommendation No.
26, especially with respect to specific
communication protocols implemented
to date. We encourage NERC to continue
its effort in working with industry with
the goal to incorporate their work into
the Reliability Standards to achieve
technical excellence as part of NERC’s
stated goal. In addition, these efforts
should include priorities that target
improving the Reliability Standards in
the near future. Specifically, NERC
should modify COM–002–0 to ‘‘tighten’’
communications, especially for
communications during alerts and
emergencies. Staff explained in the Staff
Preliminary Assessment that this can be
understood to include two key
components: (1) Effective
communications that are delivered in
clear language via pre-established
communications paths among preidentified operating entities; and (2)
communications protocols which
clearly identify that any operating
actions with reliability impact beyond a
local area or beyond a reliability

coordinator’s area must be
communicated to the appropriate
reliability coordinator for assessment
and approval prior to implementation to
ensure reliability of the interconnected
systems.149 NERC should work from
these components to develop
modifications to COM–002–0 that will
implement Blackout Report
Recommendation No. 26.
260. The Commission notes that this
Reliability Standard is applicable to
transmission operators, balancing
authorities, reliability coordinators, and
generator operators. However, during
normal and emergency operations,
communications with additional
entities are required. For example,
during emergency situations, it is
essential that the transmission operator,
balancing authority, and reliability
coordinator have communications with
distribution providers. The Commission
proposes that NERC modify the
applicability section of COM–002–1 to
make distribution providers applicable
entities and modify the requirements of
this Reliability Standard as necessary to
account for this change.
261. While the Commission has
identified concerns regarding COM–
002–1, this proposed Reliability
Standard serves an important purpose
by requiring users, owners and
operators of the Bulk-Power System to
implement the necessary
communications and coordination
among entities. NERC should provide
Measures and Levels of NonCompliance. Nonetheless, the
Requirements set forth in COM–002–1
are sufficiently clear and objective to
provide guidance for compliance.
262. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, The Commission proposes to
approve Reliability Standard COM–002–
1 as a mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to COM–
002–1 that: (1) Includes Measures and
Levels of Non-Compliance; (2) includes
a Requirement for the reliability
coordinator to assess and approve
actions that have impacts beyond the
area views of transmission operators or

147 COM–002–1,
146 Staff

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balancing authorities; 150 (3) includes
distribution providers as applicable
entities; and (4) requires tightened
communications protocols, especially
for communications during alerts and
emergencies. Alternatively, with respect
to this final issue, we propose to direct
NERC to develop a new Reliability
Standard that responds to Blackout
Report Recommendation No. 26 in the
manner just described.
4. EOP: Emergency Preparedness and
Operations
a. Overview
263. The Emergency Preparedness
and Operations (EOP) group of proposed
Reliability Standards consists of nine
Reliability Standards that address
preparation for emergencies, necessary
actions during emergencies, and system
restoration and reporting following
disturbances.
b. Emergency Operations Planning
(EOP–001–0)

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i. NERC Proposal
264. NERC’s proposed Reliability
Standard EOP–001–0 requires each
transmission operator and balancing
authority to develop, maintain, and
implement a set of plans to mitigate
operating emergencies. These plans
must be coordinated with other
transmission operators and balancing
authorities, and the reliability
coordinator. The Reliability Standard
applies to balancing authorities and
transmission operators and identifies
the regional reliability organization as
responsible for monitoring compliance.
It also requires the regional reliability
organization to review and evaluate
emergency plans every three years to
ensure that these plans consider the
elements that the Reliability Standard
specifies should be considered when
developing an emergency plan, e.g.,
system energy use, load management
and, environmental constraints.
ii. Staff Preliminary Assessment
265. Staff noted that while EOP–001–
0 requires a transmission operator and
balancing authority to develop,
maintain, and implement a set of plans
to mitigate operating emergencies
resulting from either insufficient
generation or transmission, there is no
similar requirement for a reliability
coordinator, which is the highest level
of authority responsible for the BulkPower System. Staff also found the
requirement that transmission operators
have emergency load reduction plans
150 This Requirement could be included in this
communication Reliability Standard or in an
operating Reliability Standard(s), at NERC’s option.

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capable of being implemented within 30
minutes after declaration of an operating
emergency to be ambiguous. According
to staff, the requirement could be read
to imply that load-shedding capability
with an implementation time of up to 30
minutes is acceptable to address system
emergencies. Staff deemed this
conclusion to be inappropriate. It could
expose the system to higher risk because
load shedding is the option of last resort
and must be capable of being
implemented much sooner than 30
minutes. Finally, staff noted that the
Reliability Standard does not define
transmission-related ‘‘normal,’’ ‘‘alert,’’
and ‘‘emergency’’ states, does not
provide criteria for entering into these
states, nor does it identify authority for
declaring these states.
iii. Comments
266. NERC maintains that staff’s
concerns regarding reliability
coordinator involvement are addressed
in other Reliability Standards. It states
that proposed Reliability Standard IRO–
001–0 requires a reliability coordinator
to have plans and coordination
agreements to mitigate capacity and
energy emergencies. Proposed
Reliability Standard IRO–005–0
provides more details on handling
emergencies and mitigating SOL and
IROL violations. Further, Attachment 1
to proposed Reliability Standard EOP–
002–1 provides procedures that a loadserving entity can use to work with its
reliability coordinator to obtain capacity
and energy when it has exhausted all
other options and can no longer provide
its customers’ expected energy
requirements. NERC also states that the
NERC Operating Committee approves
every reliability coordinator reliability
plan and posts those plans on its Web
site. Finally, NERC states that the 30minute limit for mitigating IROL
violations is one of many standards
gleaned from decades of interconnected
systems operation experience, and
concludes that requiring SOL and IROL
mitigation ‘‘as soon as possible’’ but
within no longer than 30 minutes is
reasonable because it allows the system
operator to decide on what course of
action to take.
267. MRO agrees with staff that the
reliability coordinator should be
required to have an emergency plan.
The requirement that load reduction
plans be capable of implementation
within 30 minutes should be clarified,
and the Reliability Standard should
include the definitions for ‘‘normal,’’
‘‘alert’’ and ‘‘emergency states.’’
However, MRO notes that these
definitions were not finalized at the

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time the Staff Preliminary Assessment
was issued.
268. ReliabilityFirst agrees that the
reliability coordinator is the highest
authority on the bulk electric system
with regard to real time, coordinated
operations. The plans mentioned in the
Reliability Standard are intended for
operators within each reliability
coordinator’s respective area.
ReliabilityFirst states that the 30 minute
load-shedding requirement establishes a
maximum threshold. It is expected that
action that can be taken prior to that
deadline will be implemented as soon
as possible.
269. The ISO/RTO Council and
Alberta agree that EOP–001–0 should
apply to reliability coordinators. ISO/
RTO Council notes that NERC’s
Reliability Coordinator Working Group
is conducting a pilot program in the
summer of 2006 to define terms to be
used in ‘‘normal,’’ ‘‘alert’’ and
‘‘emergency’’ conditions. The ISO/RTO
Council recommends that NERC adopt
these terms as part of the NERC glossary
following completion of the pilot
program.
270. CPUC comments that it is
reasonable to state that expeditious load
shedding must be available, if that is the
intent of Commission staff’s discussion
of the load-shedding timing requirement
in EOP–001–0. However, the CPUC
takes the position that it is not
reasonable to require that all load
shedding capability be available within
30 minutes. That would entail very
significant, and possibly unnecessary,
costs to the detriment of ratepayers.
iv. Commission Proposal
271. The Commission proposes to
approve proposed Reliability Standard
EOP–001–0 as mandatory and
enforceable. In addition, the
Commission proposes to direct that
NERC develop modifications to the
Reliability Standard, as discussed
below.
272. The proposed Reliability
Standard applies to transmission
operators and balancing authorities. The
Commission believes that the
applicability portion of the Reliability
Standard is sufficiently clear as to who
must comply with the filed version of
the standard and can be enforced on
these entities. However, commenters
express concern that it does not assign
a role to the reliability coordinator.
NERC states that the reliability
coordinator is the ‘‘entity that is the
highest level of authority who is
responsible for the reliable operation of
the Bulk Electric System, has the Wide
Area view of the Bulk Electric System,
and has the operating tools, processes

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and procedures, including the authority
to prevent or mitigate emergency
operating situations in both next-day
analysis and real-time operations.’’ 151
Given the importance NERC attributes
to the reliability coordinator in
connection with matters covered by
EOP–001–0, the Commission is
persuaded that this Reliability Standard
should also apply to the reliability
coordinator and proposes that it be
modified to include the reliability
coordinator as an applicable entity.
273. The proposed Reliability
Standard allows load reduction within
30 minutes of IROL violations. NERC
maintains that requiring SOL and IROL
mitigation ‘‘as soon as possible’’ but
within no longer than 30 minutes is
reasonable because it allows the system
operator to decide on what course of
action to take. The Commission
understands that it is not the intent of
this Reliability Standard to require that
shedding of all available load occur
within 30 minutes, but rather only the
amount necessary to correct system
emergencies. However, NERC’s
conclusion that IROL or SOL mitigation
within no longer than 30 minutes is
reasonable does not address the
Commission’s concern. That concern is
rooted in the view that load shedding
must be capable of being implemented
as soon as possible and much sooner
than 30 minutes. The reference to 30
minutes in EOP–001–0 could suggest
that anything up to that limit is
acceptable. Consistent with NERC’s
comments, the Commission proposes
that this Reliability Standard should be
modified to clarify that load shedding
should be capable of being implemented
as soon as possible and much less than
30 minutes.
274. Recommendation No. 20 of the
Blackout Report called for establishing
‘‘clear definitions for the normal, alert,
and emergency operational system
conditions,’’ and stated that the ‘‘roles,
responsibilities and authorities of
Reliability Coordinators and control
areas under each condition’’ should be
clarified.152 In the Commission’s view,
the inability to identify clearly when the
system is operating outside of the
normal/secure system state, and the
resulting inability to recognize the level
of reliability deterioration experienced
under all system conditions (other than
the normal/secure system state),
represents a deficiency that should be
resolved. Some ISOs and RTOs clearly
define multiple operating system states
ranging from normal to restoration.
System metering data and computer
151 NERC

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software that identify for system
operators the current system state and
clear procedures have been established
to assist the operator in returning the
system to the normal state as quickly as
possible. Indeed, the overall operational
objective is to proactively operate the
Bulk-Power System to achieve a normal
system state as contemplated by FPA
section 215.
275. The Commission believes that
there is a need for clearly defined
system states to be incorporated into
real-time operation that can
significantly improve operator
recognition of emergency conditions,
rapid and accurate response, and
recovery to normal system conditions.
In addition, a clearly defined set of
system states implemented in real-time
will help the operator proactively avert
escalation of system disturbances and
thus avert cascading outages and
reliability standard violations.
Moreover, statistics surrounding
operating states based on the duration
and frequency of excursions to nonnormal system states can provide
understanding for the operator,
management, the ERO and regulators on
how reliably the system is being
operated, how reliable it was operated
over historic periods, trends in
reliability performance and metrics that
can provide part of the foundation for
defining ‘‘an adequate level of
reliability’’ that we required in our
Order certifying the ERO.
276. We therefore propose that the
ERO modify this Reliability Standard to
include clearly defined system states for
capacity, energy, and transmission to be
implemented in real-time operations.
We note that some control areas define
and effectively use more than the
‘‘normal,’’ ‘‘alert’’ and ‘‘emergency’’
system states included in the Blackout
Report recommendations. The ERO
should determine the optimum number
of system states to be employed
continent-wide for consistency in the
development of reliability performance
metrics and should consider the
addition of the restoration state.
277. While the Commission has
identified concerns with regard to EOP–
001–0 that call for improvements, we
believe that the Reliability Standard in
its present form serves an important
purpose in promoting appropriate
planning for operating emergencies. For
instance, while we believe clarifying the
terms ‘‘normal,’’ ‘‘alert,’’ and
‘‘emergency’’ will provide for clearer
metrics for measuring performance, the
Commission believes that system
operators generally understand when
the system is in each of these states. The
Requirements are sufficiently clear and

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objective to provide guidance for
compliance.
278. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission therefore
proposes to approve Reliability
Standard EOP–001–0 as mandatory and
enforceable. In addition, pursuant to
section 215(d)(5) of the FPA and
§ 39.5(f) of our regulations, we propose
to direct that NERC submit a
modification to EOP–001–0 that: (1)
Includes the reliability coordinator as an
applicable entity with responsibilities as
described above; (2) clarifies the 30minute requirement in Requirement R2
of the Reliability Standard to state that
load shedding should be capable of
being implemented as soon as possible
and much less than 30 minutes; and (3)
includes definitions of system states to
be used by the operators, such as
transmission-related ‘‘normal,’’ ‘‘alert,’’
and ‘‘emergency’’ states, provides
criteria for entering into these states,
and identifies the authority that will
declare these states.
c. Capacity and Energy Emergencies
(EOP–002–1)
i. NERC Proposal
279. EOP–002–1 applies to balancing
authorities and reliability coordinators
and is intended to ensure that they are
prepared for capacity and energy
emergencies. NERC states that the
proposed Reliability Standard requires
that balancing authorities have the
authority to bring all necessary
generation on line, communicate the
energy and capacity emergency with the
reliability coordinator, and coordinate
with other balancing authorities. NERC
also states that the Reliability Standard
limits a balancing authority’s use of any
other balancing authority’s bias
contribution to the Interconnection,
referred to as ‘‘leaning on the ties.’’
EOP–002–1 includes an attachment that
describes an emergency procedure to be
initiated by a reliability coordinator that
declares one of four energy emergency
alert levels to provide assistance to the
load serving entity.
ii. Staff Preliminary Assessment
280. The Staff Preliminary
Assessment explained that while EOP–
002–1 addresses responsibility,
authority and actions to be taken to
alleviate a generation capacity and
energy emergency, it does not address
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transmission capability, nor is this issue
addressed elsewhere in other proposed
Reliability Standards. Staff noted that
transmission loading relief (TLR)
procedures discussed in Reliability
Standard IRO–006–3 are not appropriate
for addressing actual transmission
emergencies since, as stated in the
Blackout Report, they are ‘‘not fast and
predictable enough for use in situations
in which an Operating Security Limit is
close to or actually being violated.’’ 153

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iii. Comments
281. NERC states that, while EOP–
002–1 does not address emergencies
resulting from insufficient transmission
capability, a number of other proposed
Reliability Standards related to
transmission operation and reliability
coordination address the need to
operate within facility limits, SOL and
IROL. NERC states that collectively the
proposed Reliability Standards address
emergencies resulting from insufficient
transmission capability.
282. MRO and ReliabilityFirst state
that they agree with staff’s assessment of
EOP–002–1. In addition, MRO states
that TLRs are not appropriate for
addressing actual transmission
emergencies for the reasons stated in the
Blackout Report.
283. The ISO/RTO Council states that
before approving EOP–002–1, the
Commission should direct NERC to
include in that Reliability Standard a
requirement to assess whether sufficient
transmission capability exists to allow
the capacity and energy emergency plan
mandated by the Reliability Standard to
be ‘‘robust enough to ensure adequate
resources.’’ The ISO/RTO Council also
agrees with staff’s concerns that TLRs
are not appropriate for addressing actual
transmission emergencies for the
reasons stated in the Blackout Report. It
notes that ISOs and RTOs use
redispatch to correct SOL and IROL
instead of TLR procedures. Moreover,
the ISO/RTO Council states that ISOs
and RTOs that redispatch to protect
system reliability do not get credit for
such actions when another entity
declares a TLR event. It also states that
redispatch allows for a far more
targeted, and thus effective, tool to
resolve an imminent reliability threat
than does a TLR, which can trigger
additional TLRs on neighboring
systems. As a result, the applicability of
any Reliability Standard that relies on
TLRs as the specific reliability tool to be
used in an ISO or RTO region could be
detrimental to system reliability.
153 Id.

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iv. Commission Proposal
284. The Commission shares the
concern expressed by MRO and the ISO/
RTO Council that the Emergency Plan
required by EOP–002–1 addresses only
generation capacity and energy
emergencies and does not address
emergencies resulting from inadequate
transmission capability. NERC states
that other Reliability Standards address
mitigation of SOL and IROL violations
due to loss of transmission facilities.
While we agree with NERC that other
Reliability Standards address mitigation
of SOL and IROL violations, we remain
concerned that neither EOP–002–1 nor
any other Reliability Standard addresses
the impact of inadequate transmission
during generation emergencies.
285. Requirement R6 of EOP–002–1
identifies various remedies that a
balancing authority should use to
comply with Control Performance and
Disturbance Control Standards
including loading all available
generating capacity and deploying all
available operating reserve. The
Commission proposes that the ERO
modify Requirement R6 to include use
of demand side management as one of
the possible remedies.
286. MRO and the ISO/RTO Council
express concern that the TLR method is
inappropriate for addressing actual
transmission emergencies. The
Commission’s proposal to address this
concern is discussed fully in relation to
Reliability Standards IRO–006–3 where
the use of TLRs to mitigate potential or
actual SOL and IROL violations is
specified in these standards. The
Commission shares the concerns of
commenters about the use of TLR
procedures for reasons stated in the
Blackout Report, i.e., they are not fast
and predictable enough for use in
situations in which an operating
security limit is close to being, or
actually is being, violated. The
Commission therefore proposes to
instruct the ERO to include a clear
warning that the TLR procedure is an
inappropriate and ineffective tool to
mitigate IROL violations or for use in
emergency situations.
287. While the Commission has
identified concerns with regard to EOP–
002–1 that call for improvements, we
believe that the proposed Reliability
Standard serves an important purpose
in promoting the goal of ensuring that
balancing authorities and reliability
coordinators are prepared for capacity
and energy emergencies. In addition, the
Requirements of the proposed
Reliability Standard are sufficiently
clear and objective to provide guidance
for compliance. Accordingly, giving due

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weight to the technical expertise of the
ERO and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard EOP–002–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to EOP–
002–1 that: (1) Addresses emergencies
resulting not only from insufficient
generation but also from insufficient
transmission capability, including
situations where insufficient
transmission impacts the
implementation of the capacity and
energy emergency plan; (2) identifies
demand side management in
Requirement R6 as one possible remedy
that a balancing authority should use to
bring it in compliance with Control
Performance and Disturbance Control
Standards; and (3) includes a clear
warning that the TLR procedure is an
inappropriate and ineffective tool to
mitigate IROL violations or for use in
emergency situations.
d. Load Shedding Plans (EOP–003–0)
i. NERC Proposal
288. EOP–003–0 deals with loadshedding plans and requires that
balancing authorities and transmission
operators operating with insufficient
transmission and generation capacity
have the capability and authority to
shed load rather than risk a failure of
the Interconnection. The proposed
Reliability Standard includes
requirements to establish plans for
automatic load shedding for
underfrequency or undervoltage,
manual load shedding to respond to
real-time emergencies, and
communication with other balancing
authorities and transmission operators.
NERC indicates that it plans to modify
EOP–003–0 to include Measures and
Levels of Non-Compliance.
ii. Staff Preliminary Assessment
289. Staff stated that EOP–003–0 does
not specify the minimum load-shedding
capability that should be provided and
the maximum amount of delay before
load shedding can be implemented.
Staff noted that this Reliability Standard
does not require that safeguards be
provided to shield operators from
retaliation when they declare an
emergency or shed load in accordance
with previously approved guidelines, as

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the Blackout Report recommends.154 In
addition, the Staff Preliminary
Assessment observed that the Reliability
Standard does not require periodic
drills of simulated load shedding. It
stated that such drills are important to
test the effectiveness of the processes,
communications and protocols, and to
familiarize operators from reliability
coordinators, transmission operators
and load serving entities with their
respective roles and responsibilities in
connection with the load shedding
plans.
iii. Comments
290. NERC states that it considers
operator liability to be a regulatory
rather than a reliability issue, but that it
has taken relevant action on two fronts.
First, Version 0 of the proposed
Reliability Standards provides direction
to operators on when they should
manually initiate load shedding, and
expects operators to be empowered to
take whatever action is necessary to
ensure the reliability of the Bulk-Power
System without fear of liability claims.
Second, the regional reliability
organizations are reviewing the
applicability of automatic load-shedding
plans in specific geographic areas, and
are to present their recommendations to
NERC.
291. MRO states that the requirement
that the balancing authority and
transmission operator have the
capability and authority to shed load
rather than risk an uncontrolled failure
is sufficient to meet the intent of this
Reliability Standard and that the
additional information suggested by
staff is unnecessary. MRO maintains
that the amount of load to be shed and
the timeframe for shedding it is directly
related to the system problem or
condition at the time of the event.
Adding an expected percentage and
timeframe will not improve the
Reliability Standard and would likely
not meet every situation or system
condition. MRO also concurs with staff
that the Reliability Standard should
require periodic drills of simulated load
shedding and suggests that NERC better
identify the type of training that should
include load shed drills.
292. MidAmerican shares staff’s
concerns and suggests that the
Reliability Standard should mandate
regional studies to determine the
appropriate minimum requirements for
load shedding, recognizing the regional
network is a portion of the
interconnected network. It notes that
certain portions of the Eastern
Interconnection are not susceptible to
154 Id.

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instability, uncontrolled separation and
cascading, while other portions of the
Eastern Interconnection are very
susceptible to these events.
MidAmerican states that it may be more
important to provide additional loadshedding capabilities in the portion of
the Interconnection that is more
susceptible to instability.
293. Southern, ReliabilityFirst and
MRO agree with staff that transmission
operators who initiate load shedding
pursuant to guidelines should be
shielded from liability or retaliation.
Southern states that it seems more
appropriate to also address limitation of
liability in each transmission owner’s
OATT. Southern also submits that the
role of the reliability coordinator as
currently established under EOP–003–0
is appropriate and is consistent with its
role in maintaining reliability. Southern
states that while the reliability
coordinator should be aware of the
restoration plan required by the
Reliability Standard, approval of that
plan would have no clear benefit.
iv. Commission Proposal
294. As discussed above, EOP–003–0
does not specify the minimum loadshedding capability that should be
provided and the maximum amount of
delay before load shedding can be
implemented. The Commission
disagrees with MRO’s position that
adding a minimum load shedding
capability and timeframe will not
improve the Reliability Standard
because the Reliability Standard does
not specify amount or timeframe to shed
load. The actual amount of load to be
shed, location and timeframe will be at
the discretion of the system operator
based on the nature of the system
problem and his assessment of
corrective actions required. However, if
the capability to shed sufficient load in
locations where it is required and in a
timely manner is not available to the
system operator then the risk of
uncontrolled failure of system elements
or cascading outages is increased due to
no or delayed actions to shed load. The
Commission agrees with MidAmerican
that specifying a minimum capability
and maximum allowable delay is
necessary to ensure an adequate loadshedding plan to contain a disturbance
and prevent system cascading. The
Commission proposes that the
Reliability Standard should be modified
to address this matter. We recognize that
this issue may be addressed on a
regional basis if it meets the
requirements for a regional difference as
suggested by MidAmerican.
295. Blackout Report
Recommendation No. 8, which is

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addressed to ‘‘legislative bodies and
regulators,’’ recommends that operators
who initiate load shedding pursuant to
approved guidelines should be shielded
from ‘‘liability suits or other forms of
retaliation, provided their action is
pursuant to previously approved
guidelines.’’ 155 Neither the Commission
nor the ERO has authority under section
215 of the FPA to shield operators from
liability suits for actions that they take
or fail to take. Further, the Commission
believes that an added Requirement to
shield operators from retaliation would
be vague and beyond the scope of the
Reliability Standard. As explained by
NERC, the proposed Reliability
Standards provide direction to operators
on when they should manually initiate
load shedding. The goal of EOP–003–0
is to ensure that a transmission operator
‘‘must have the capability and authority
to shed load’’ and the Requirements
provide the specifics on how this is to
be achieved. We believe that this is
sufficient to empower operators to take
necessary action to ensure the reliability
of the Bulk-Power System. The
Commission notes that NERC has
required each transmission operator
post a letter from its CEO stating that
there will be no retaliation against
system operators that shed load in
accordance with approved corporate
policies and procedures. A review of
such letters is included in NERC
Readiness Reviews. The Commission
believes that this is an acceptable
approach.
296. MRO concurs with staff that the
Reliability Standard should require
periodic drills of simulated load
shedding. It suggests that NERC better
identify the type of training that is
required to include load shed drills.
Load shedding drills will improve the
operator response to emergencies,
including timely implementation of
load shedding. The Commission
therefore proposes to direct the ERO to
modify this Reliability Standard to
require periodic drills of simulated load
shedding.
297. The Reliability Standard does not
contain any Measures or Levels of NonCompliance. The Commission proposes
that it be modified to address this
deficiency.
298. While the Commission has
identified concerns with regard to EOP–
003–0, we believe that the proposal
serves an important purpose in ensuring
load-shedding plans are developed and
that appropriate capability and
authority for load shedding exists. As
noted above, EPO–003–0 raises several
issues that require NERC’s attention.
155 Id.

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Nonetheless, the proposed
Requirements set forth in EOP–003–0
are sufficiently clear and objective to
provide guidance for compliance.
299. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard EOP–003–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to EOP–003–0 that (1) specifies the
minimum load-shedding capability that
should be provided and the maximum
amount of delay before load shedding
can be implemented; (2) requires
periodic drills of simulated load
shedding; and (3) contains Measures
and Levels of Non-Compliance.
e. Disturbance Reporting (EOP–004–0)
i. NERC Proposal
300. Proposed Reliability Standard
EOP–004–0 establishes requirements for
reporting system disturbances to the
regional reliability organization and the
ERO. It also establishes requirements for
the analysis of these disturbances. NERC
indicates that the Reliability Standard’s
purpose is to minimize the likelihood of
similar events in the future. NERC states
that EOP–004–0 is linked to DOE
disturbance reporting requirements and
Energy Information Administration
(EIA) Form 417.

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ii. Staff Preliminary Assessment
301. Commission staff noted that
EOP–004–0 does not address the
Blackout Report’s recommendation that
a standing framework be established for
conducting future blackout and
disturbance investigations. Staff noted
that the U.S. Department of Energy
(DOE) made a presentation to the NERC
Board of Trustees on preparing for an
investigation, priority actions following
a blackout, and the investigation
process. Staff also noted that NERC has
prepared a procedure for responding to
major events that affect the bulk electric
system. Staff indicated it believes that
the DOE presentation and the NERC
procedure provide a reasonable basis for
revising EOP–004–0. In addition, staff
noted that the Reliability Standard does
not contain any Measures or Levels of
Non-Compliance. Staff acknowledged
that NERC has indicated this deficiency
will be addressed and that the
Reliability Standard will be resubmitted

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for Commission approval in November
2006.
iii. Comments
302. NERC states that procedures to
conduct future blackout and disturbance
investigations should not be included in
the Reliability Standards. NERC states
that it has developed these procedures
and that they are provided as an
appendix to its proposed ERO Rules of
Procedure.
303. MRO supports staff’s conclusion
that this Reliability Standard does not
address the Blackout Report’s
recommendation that a standing
framework be established for
conducting future blackout and
disturbance investigations. MRO
maintains that NERC and the DOE
procedures provide a formal process for
investigating disturbances.
iv. Commission Proposal
304. The Commission agrees with the
MRO that this Reliability Standard does
not address the Blackout Report’s
Recommendation No. 14 to establish a
standing framework for conducting of
future blackout and disturbance
investigations and proposes that the
Reliability Standard be modified to
specify those requirements included in
the ERO Rules of Procedure that apply
to users, owners and operators of BulkPower System. NERC states that it has
developed these procedures, and they
are provided as an appendix to its
proposed ERO Rules of Procedure.
Although the Commission
acknowledges that, under § 39.2 of our
regulations, all users, owners and
operators of the Bulk-Power System
must comply with the ERO Rules,
which includes its Rules of Procedure,
we believe that requirements outlined in
these procedures that apply to users,
owners and operators of the Bulk-Power
System must be included in this
Reliability Standard, but not the rules of
procedure themselves, so that they
become mandatory and enforceable. The
Commission believes that including
these requirements in this Reliability
Standard will promote system reliability
by ensuring that users, owners and
operators of the Bulk-Power System
provide data to assist NERC
investigations and ensuring that the
Reliability Standard is clear and
complete. Such requirements include
the provision of system disturbance
data, voice recordings and other
information collected during the event
to support the analysis of the event after
the fact. Therefore, we propose to direct
that NERC modify EOP–004–0 to
include any requirements necessary for
users, owners and operators of the Bulk-

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Power System to provide data that will
assist NERC in the investigation of a
blackout or disturbance.
305. While the Commission has
identified concerns with regard to EOP–
004–0, we believe that the proposal
serves an important purpose in
establishing requirements for reporting
and analysis of system disturbances.
While the Commission believes that
additional Requirements are needed, the
proposed Requirements set forth in
EOP–004–0 are sufficiently clear and
objective to provide guidance for
compliance.
306. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard EOP–004–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to EOP–004–0 that: (1) includes any
requirements necessary for users,
owners and operators of the Bulk-Power
System to provide data that will assist
NERC in the investigation of a blackout
or disturbance; and (2) includes
Measures and Levels of NonCompliance.
f. System Restoration Plans (EOP–005–
1)
i. NERC Proposal
307. Proposed Reliability Standard
EOP–005–1 156 deals with system
restoration plans and requires that
plans, procedures, and resources be
available to restore the electric system to
a normal condition in the event of a
partial or total system shut down. The
Reliability Standard requires
transmission operators, balancing
authorities, and reliability coordinators
to have effective restoration plans, to
test those plans, and to be able to restore
the interconnection using them
following a blackout. It also requires
operating personnel to be trained in
these plans.
308. NERC’s August 28, 2006
Supplemental Filing included a revised
version of EOP–005, designated EOP–
005–1. The revised Reliability Standard
includes two new Requirements, R9 and
156 On August 28, 2006, NERC submitted EOP–
005–1 for approval, which replaces EOP–005–0.
EOP–005–1 is the same as EOP–005–0 except for
the changes noted above. Thus, comments
submitted in response to the Staff Preliminary
Assessment on EOP–005–0 apply equally to EOP–
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R10, and two revised requirements, R4
and R8. The new Requirement R9
requires that the transmission operator
document the cranking paths, including
initial switching requirements, between
each blackstart generating unit and the
unit(s) to be started. The new
Requirement R10 requires the
transmission operator to demonstrate
through simulation or testing, the
blackstart units can perform their
intended function and that simulation
or testing be performed at least once
every five years. The revised
Requirement R4 requires the
transmission operator to coordinate its
restoration plans with the generator
owners in addition to others. The
revised Requirement R8 requires
transmission operators to verify that the
number, size, availability, and location
of system blackstart generating units are
sufficient to meet regional reliability
organization restoration plan
requirements for the transmission
operator’s area.

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ii. Staff Preliminary Assessment
309. Staff noted that, while EOP–005–
0 requires that operators be trained in
the implementation of the restoration
plan, it does not require this to be done
periodically. In addition, the Reliability
Standard contains Levels of NonCompliance but no Measures. Staff
noted that NERC has not identified this
Reliability Standard as one that would
be modified and resubmitted for
Commission approval in November
2006.
iii. Comments
310. MRO comments that EOP–005–0
should identify the timeframes for
operator training and restoration plan
review. National Grid comments that
the Staff Preliminary Assessment does
not offer any specific time interval over
which periodic training of operators
should occur and that the Commission
and NERC should work together to
establish a balanced training interval
when establishing requirements for
periodic training on restoration plan
procedures.
311. Alcoa states that two
Requirements of EOP–005–0 either
overlap with or are duplicative of
Requirements contained in other
proposed Reliability Standards, in
particular COM–001–0. Alcoa states that
any overlapping or duplicative
requirements that can lead to multiple
interpretations regarding compliance
which could hinder system reliability.
Alcoa suggests that the Reliability
Standard can be improved by defining
minimum requirements relating to the
periodic monitoring of

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telecommunications facilities and by
giving some attention to the technical
requirements of ‘‘essential
telecommunications facilities.’’
312. Alberta states that EOP–005–0 is
an example of a Reliability Standard
that should not be approved but should
continue as a voluntary Reliability
Standard unless it is determined that
the Reliability Standard would have an
adverse effect on system reliability.
Alberta states that Requirement R1 of
the Reliability Standard is missing
elements—although it does not identify
them—and lacks measurability, and it
therefore should remain voluntary until
it is revised.157
iv. Commission Proposal
313. The Commission agrees with
MRO and National Grid that the
Reliability Standard should identify
time frames for training, drills and
review of restoration plan requirements
to simulate contingencies and prepare
operators for anticipated and unforeseen
events. Periodic training, drills and plan
review is necessary to ensure that the
Reliability Standard effectively
promotes Bulk-Power System reliability,
and specific training and review time
frames will enhance the effectiveness of
the Reliability Standard.
314. The Commission does not agree
with Alcoa that the telecommunication
testing requirements in COM–001–0 and
EOP–005–0 can lead to multiple
interpretations regarding compliance.
315. The Commission believes that
new Requirements R9 and R10 included
in EOP–005–1 would contribute to
maintaining or enhancing system
reliability and therefore proposes to
accept them.
316. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard EOP–005–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to EOP–005–1 that (1) includes
157 Requirement R1 provides that ‘‘[e]ach
Transmission Operator shall have a restoration plan
to reestablish its electric system in a stable and
orderly manner in the event of a partial or total
shutdown of its system, including necessary
operating instructions and procedures to cover
emergency conditions, and the loss of vital
telecommunications channels. Each Transmission
Operator shall include the applicable elements
listed in Attachment 1–EOP–005–0 in developing a
restoration plan.’’

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Measures; and (2) identifies time frames
for training and review of restoration
plan requirements to simulate
contingencies and prepare operators for
anticipated and unforeseen events.
g. Reliability Coordination-System
Restoration (EOP–006–0)
i. NERC Proposal
317. Proposed Reliability Standard
EOP–006–0 deals with reliability
coordination and system restoration. It
establishes specific requirements for
reliability coordinators during system
restoration, and it states that reliability
coordinators must have a coordinating
role in system restoration to ensure that
reliability is maintained during
restoration and that priority is placed on
restoring the Interconnection.
ii. Staff Preliminary Assessment
318. The Staff Preliminary
Assessment noted that EOP–006–0
requires only that reliability
coordinators, which are the highest
authority responsible for overall system
restoration, are aware of the restoration
plan of each transmission operator in its
reliability coordination area, but it does
not require that they be involved in the
plan’s development or approval. Staff
also noted that the Reliability Standard
does not contain any Measures, metrics
or processes to assess compliance with
its requirements or any Levels of NonCompliance. Staff acknowledged that
NERC has indicated that the Reliability
Standard will be modified to address
these deficiencies and resubmitted for
Commission approval in November
2006.
iii. Comments
319. NERC states that Requirement R3
of EOP–006–0 requires the reliability
coordinator to have an area restoration
plan. NERC asserts that the reliability
coordinator will have input into the
transmission operators’ restoration
plans to ensure those plans are
coordinated. NERC acknowledges that
there may be merit in requiring
reliability coordinators to approve the
restoration plans.
320. MRO agrees with staff in that
reliability coordinators should be
required to be involved in the
development and approval of
restoration plans. MRO supports the
inclusion of Measures and Levels of
Non-Compliance.
321. Southern submits that the role of
the reliability coordinator as currently
established is appropriate and is
consistent with the role of the reliability
coordinator in maintaining reliability. It
states that while the reliability
coordinator should be aware of the

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that they can perform their expected
functions as specified in the overall
coordinated regional system restoration
plans.

restoration plan required by the
Reliability Standard, approval of that
plan would have no clear benefit.
iv. Commission Proposal
322. The Commission agrees with
MRO and NERC that the reliability
coordinators should be involved in the
development and approval of the
restoration plans. The reliability
coordinator’s position as the highest
authority responsible for system
reliability and system restoration
justifies its involvement in the
development and approval of these
plans. The Commission thus disagrees
with Southern that the reliability
coordinator’s involvement would have
no clear benefit. The Commission
proposes that the Reliability Standard
be modified to require that the
reliability coordinator be involved in
the development and approval of
restoration plans. The Commission also
proposes to direct NERC to include
Measures and Levels of Noncompliance.
323. While the Commission has
identified concerns with regard to EOP–
006–0, we believe that the proposal
serves an important purpose in
promoting reliability coordination and
system restoration. Further, the
proposed Requirements set forth in
EOP–006–0 are sufficiently clear and
objective to provide guidance for
compliance. Accordingly, giving due
weight to the technical expertise of the
ERO and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard EOP–006–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to EOP–
006–0 that: (1) requires that the
reliability coordinator be involved in
the development and approval of
restoration plans; and (2) includes
Measures and Levels of NonCompliance.

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h. Establish, Maintain, and Document a
Regional Blackstart Capability Plan
(EOP–007–0)

ii. Staff Preliminary Assessment
325. Staff noted in the Staff
Preliminary Assessment that Reliability
Standard EOP–007–0 lists only the
regional reliability organization as the
applicable entity and stated that the
appropriateness of designating the
regional reliability organization as the
applicable entity is a concern in the new
mandatory Reliability Standard
structure.
iii. Comments
326. ReliabilityFirst states that the
blackstart procedures developed by the
individual regions need to be merged to
develop consistent procedures.
327. EEI states that, for the most part,
the Reliability Standard involves
collection management and reporting
requirements, although it notes that
blackstart generation plans have
reliability operation implications. MRO
expresses concern that EOP–007–0 is an
operating function rather than a
Reliability Standard. MRO states that if
EOP–007–0 remains a Reliability
Standard, it should be revised to require
that operating entities have a restoration
and blackstart capability plan, and EEI
states that it should be redrawn so that
compliance obligations are assigned
directly to those entities that provide
the data and other information. In
addition, MRO states that the regional
reliability organization should be
removed as an applicable entity.
iv. Commission Proposal
328. Consistent with our discussion in
the Common Issues section above, the
Commission will not propose to accept
or remand EOP–007–0, as it applies
only to regional reliability
organizations. The Commission believes
that, in the long-run, the Regional
Entities should be responsible for
establishing, maintaining and
documenting regional blackstart
capability plans. However, during the
current period of transition, the regional
reliability organizations should
continue to perform this role as they
have in the past.

i. NERC Proposal

i. Plans for Loss of Control Center
Functionality (EOP–008–0)

324. NERC states that proposed
Reliability Standard EOP–007–0, which
deals with establishing, maintaining and
documenting regional blackstart
capability plans, ensures that the
quantity and location of system
blackstart generators are sufficient and

i. NERC Proposal
329. Proposed Reliability Standard
EOP–008–0 deals with plans for loss of
control center functionality. It requires
that each reliability coordinator,
transmission operator and balancing
authority have a plan to continue

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reliable operations and to maintain
situational awareness in the event its
control center is no longer operable.
ii. Staff Preliminary Assessment
330. Staff noted that EOP–008–0
requires the applicable entities to have
a backup plan, but it does not
specifically require that backup
capabilities be provided. The Reliability
Standard does not address requirements
for independence from the primary
control center, provide for prolonged
operation or provide the minimum tools
and facilities consistent with the roles,
responsibilities and tasks of the
different entities to which it applies.
iii. Comments
331. NERC agrees with Commission
staff that the proposed Reliability
Standard does not adequately address
the requirements for backup of critical
control center functionality, and it
proposes that such a Reliability
Standard should be developed. NERC
states that the possible solutions for
providing backup of critical Bulk-Power
System operating functionality are not
limited to a redundant control center.
Neighboring systems can provide such
functionality as contracted services, or
they can be provided through backup
equipment within a separate existing
facility.
332. EEI supports EOP–008–000 as
technically sound. It states that the
Reliability Standard requires
implementation of the plan by defining
as a Level 4 violation a failure to
implement the plan. This clearly
establishes that backup capabilities
must exist as reflected in the plan.
According to EEI, entities must have
communications facilities that do not
rely on the primary control center; and
that procedures must be in place for
monitoring and controlling critical
facilities, and for maintaining voice
communications capability with other
areas.158
333. MRO, ReliabilityFirst and the
ISO/RTO Council agree with staff’s
evaluation of EOP–008–0. MRO states
that this Reliability Standard requires a
backup plan, but does not address the
requirements for independence from the
primary control center, does not provide
for prolonged operation, does not
provide the minimum tools and
facilities consistent with the roles,
responsibilities and tasks of the
different entities. MRO suggests that
NERC should modify this Reliability
Standard accordingly. MRO notes that
today many companies simply have a
plan and do not have an actual backup
158 EEI

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facility. It states that the new
requirements would have to take effect
at some time in the future and that this
Reliability Standard needs to make clear
that the backup site should be capable
of withstanding anticipated disasters,
such as the hurricanes in Florida.
ReliabilityFirst states that EOP–008–0
should include additional detail on
dealing with prolonged primary control
center inoperability. The ISO/RTO
Council states that meeting the
shortcomings staff identified in EOP–
008–0 will require identification of
minimum required tools and facilities
and definition of the appropriate
entities responsibilities.
iv. Commission Proposal
334. Staff raised the concern that
EOP–008–0 requires the applicable
entities to have a backup plan, but it
does not specifically require that backup
capabilities be available. EEI comments
that the Reliability Standard implicitly
requires backup capabilities because a
Level 4 violation occurs when an entity
fails to implement such a plan. The
Commission disagrees with EEI that
such a Requirement can be discerned
from Level 4 Non-Compliance. As we
explained in our policy discussion in
Measures and Levels of NonCompliance, NERC has stated that the
‘‘Requirements’’ within a Reliability
Standard define what an entity must do
to be compliant and establish an
enforceable obligation, and the presence
or absence of Measures or Levels of
Non-Compliance should not be the sole
determining factor as to whether a
Reliability Standard meets the statutory
test for approval.
335. Thus, the Commission believes
that provision for backup capabilities
should be an explicit Requirement.
Such backup capability, at a minimum,
must: (1) Be independent of the primary
control center; (2) be capable of
operating for a prolonged period of time;
and (3) provide for a minimum set of
tools and facilities to replicate the
critical reliability functions of the
primary control center.159 The
Commission proposes that NERC
modify the standard accordingly. In
addition to the three capability
requirements identified above, the
Commission is interested in comments
from industry concerning other specific
capabilities.
336. The Commission understands
that backup control facilities can be
costly but, when needed, are essential
for reliability. To address the balance
159 Facilities

examples include
telecommunications, backup power supplies,
computer systems, and security systems

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between cost and reliability benefits,
there needs to be some flexibility on
how the capability is achieved. For
example, the mechanism to provide
these capabilities may include building
fully redundant physical back up
control centers or, as NERC suggests,
contracting back up control services or
through backup equipment within a
separate existing facility. However, the
Commission proposes that the extent of
the backup capability be consistent with
the impact of the loss of the entity’s
primary control center on the reliability
of the Bulk-Power System. Further, the
Commission proposes to direct NERC to
modify the standard to include a
Requirement that all reliability
coordinators have full backup control
centers since they are essential to BulkPower System reliability. In addition,
the Commission is interested in
comments on what other entities should
have full backup centers for reliability
such as balancing authorities and large
transmission operators.
337. While the Commission has
identified concerns with regard to EOP–
008–0, we believe that the proposal
serves an important purpose in ensuring
that applicable entities have a backup
plan in the case of loss of control center
functionality. While the Commission
believes that additional Requirements
are needed, the proposed Requirements
set forth in EOP–008–0 are sufficiently
clear and objective to provide guidance
for compliance. Accordingly, giving due
weight to the technical expertise of the
ERO and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard EOP–008–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to this
Reliability Standard that includes a
Requirement that provides for backup
capabilities, as described above.
j. Documentation of Blackstart
Generating Unit Tests Results (EOP–
009–0)
i. NERC Proposal
338. Proposed Reliability Standard
EOP–009–0 deals with documentation
of blackstart generating unit test results.
NERC states that this Reliability
Standard ensures that the quantity and
location of system blackstart generators
are sufficient and that these generators
can perform their expected functions as

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specified in overall coordinated regional
system restoration plans.
ii. Staff Preliminary Assessment
339. Staff noted in the Staff
Preliminary Assessment that this
Reliability Standard requires that the
start-up and operation of each
generating blackstart unit be tested and
that the results be submitted to the
regional reliability organization.
However, it does not require that
blackstart units be periodically tested to
ensure that they will be available when
required to restore the system.
iii. Comments
340. NERC and other commenters
point out that Reliability Standard EOP–
007–0 requires the routine testing, i.e.,
minimum testing of one-third of
blackstart units each year, suggested by
staff.
iv. Commission Proposal
341. The Commission is satisfied with
the explanation of NERC and other
commenters that Reliability Standard
EOP–007–0 requires periodic testing of
blackstart units.
342. The Commission believes that
the proposal serves an important
purpose in ensuring adequate blackstart
generation capability. Further the
proposed Requirements set forth in
EOP–009–0 are sufficiently clear and
objective to provide guidance for
compliance. Accordingly, the
Commission believes that Reliability
Standard EOP–009–0 is just, reasonable,
not unduly discriminatory or
preferential, and in the public interest;
and proposes to approve it as mandatory
and enforceable.
5. FAC: Facilities Design, Connections,
Maintenance, and Transfer Capabilities
a. Overview
343. The nine Facility (FAC)
Reliability Standards address topics
such as facility connection
requirements, facility ratings, system
operating limits, and transfer
capabilities. The standards also
establish requirements for maintaining
equipment and rights-of-way, including
vegetation management.
344. How transmission local control
centers are incorporated into the
transmission operator definition will be
the same as is described in the COM
Chapter.
b. Facility Connection Requirements
(FAC–001–0)
i. NERC Proposal
345. Proposed Reliability Standard
FAC–001–0 is intended to ensure that

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transmission owners establish facility
connection and performance
requirements to avoid adverse impacts
to the Bulk-Power System.
ii. Staff Preliminary Assessment
346. The Staff Preliminary
Assessment did not identify any issues
related to this Reliability Standard.
iii. Comments
347. No specific comments were
received.
iv. Commission Proposal
348. This Reliability Standard is
necessary to ensure standard procedures
and performance assessments for new
interconnection facilities. Further, the
Requirements in FAC–001–0 are
sufficiently clear and objective to
provide guidance for compliance. Thus,
the Commission proposes to approve
Reliability Standard FAC–001–0 as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.
c. Coordination of Plans for New
Generation, Transmission, and End-User
Facilities (FAC–002–0)
i. NERC Proposal
349. Proposed Reliability Standard
FAC–002–0 requires that each
generation owner, transmission owner,
distribution provider, load-serving
entity, transmission planner, and
planning authority assess the impact of
integrating generation, transmission,
and end-user facilities into the
interconnected transmission system.

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ii. Staff Preliminary Assessment
350. Requirement R1 of FAC–002–0
requires system performance
assessments in accordance with
Standard TPL–001–0,160 which relates
only to normal system conditions. Staff
pointed out that performance
requirements for new generation
interconnection in Order No. 2003 161
require assessment for both normal and
160 Standard TPL–001–0 (Requirement 1 states
that ‘‘The Planning Authority and Transmission
Planner shall each demonstrate through a valid
assessment that its portion of the interconnected
transmission system is planned such that, with all
transmission facilities in service and with normal
(pre-contingency) operating procedures in effect,
the Network can be operated to supply projected
customer demands * * *’’).
161 Standardization of Generator Interconnection
Agreements and Procedures, Order No. 2003, 68 FR.
49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146
(2003), order on reh’g, Order No. 2003–A, 69 FR
15932 at P 89 and 145 (Mar. 26, 2004), FERC Stats.
& Regs. ¶ 31,160 (2004), order on reh’g, Order No.
2003–B, 70 FR 265 (Jan. 4, 2005), FERC Stats. &
Regs. ¶ 31,171 (2004), order on reh’g, Order No.
2003–C, 70 FR 37661 (June 30, 2005), FERC Stats.
& Regs. ¶ 31,190 (2005); see also Notice Clarifying
Compliance Procedures, 106 FERC 1,009 (2004).

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post-contingency conditions and is
therefore more rigorous than TPL–001–
0.
iii. Comments
351. NERC comments that, while the
staff evaluation of FAC–002–0 is valid,
the Reliability Standard should
nonetheless be approved. NERC offers
that it will continue to improve the
Reliability Standard. Likewise, MRO
and ISO/RTO Council agree with staff’s
evaluation of FAC–002–0. MRO adds
that an effort should be made to align or
combine the requirements of Order No.
2003 and the NERC Reliability
Standards into a single set of standards.
ISO/RTO Council expresses concern
that the Reliability Standard does not
identify parties responsible for
particular tasks, stating that it should be
reviewed to ensure that tasks are
correctly assigned.
352. NERC and others state that
Requirement R1 of FAC–002–0 should
require not only the use of TPL–001–0,
but also TPL–002–0, and TPL–003–0.
Similarly, ReliabilityFirst believes that
FAC–002–0 contains an error in
Requirement R1.4. It alleges that the
requirement should have been
translated to refer to standards TPL–
001–0 through TPL–004–0 instead of
only referencing TPL–001–0. Similarly,
ISO/RTO Council submits that
Requirements R1.1 through R1.5 need to
include a reference to standard TPL–
002–0.
353. Alcoa points out that
Requirements R1.1 and R1.2 lack
metrics. Alcoa asserts that these
Requirements are broadly-worded,
open-ended and suggest that even a
small addition of facilities would
compel an entity to comply with all of
the Reliability Standards, which might
not otherwise apply.
354. CenterPoint contends that
coordination cannot be audited with an
objective auditable measure and
recommends that this standard be
eliminated. CenterPoint notes tradeoffs
involved in planning interconnections
for generators can put transmission
service providers at risk for either
accusation by the ERO of failing to
provide adequate facilities or accusation
by state commissions of ‘‘gold-plating,’’
or not performing proper generation
interconnection planning. CenterPoint
adds that although staff has discussed
planning for the most onerous
conditions, real-life application of this
is more complex because it needs to be
based on the reasoned judgment of
experts considering particular facts as
opposed to rigid standards.
355. MEAG asserts that including
distribution providers in FAC–002–0 is

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unnecessarily redundant and potentially
overbroad because the Reliability
Standard should not apply to
distribution providers that do not own
generation or transmission facilities. It
explains that, if a distribution provider
owns facilities that are integral to the
transmission system, then the
distribution provider is also a
transmission owner, according to the
‘‘NERC glossary of Terms Used in
Reliability Standards.’’ Likewise, if a
distribution provider owns generating
facilities, then the distribution provider
is a generator owner. However, if each
load-serving entity provides the
transmission owner with its load
characteristics and the distribution
provider does not own integral
generation or transmission facilities,
then MEAG concludes that FAC–002–0
should not apply to such distribution
providers.
iv. Commission Proposal
356. The Commission agrees with
NERC and others that the Reliability
Standard should refer not only to TPL–
001, but also to TPL–002–0 and TPL–
003–0, which relate to loss of one or
more Bulk-Power System elements. This
would improve the technical soundness
of the Reliability Standard by
appropriately broadening the scope of
system performance assessments to
include post-contingency conditions. In
addition, such a modification would
achieve greater consistency with Order
No. 2003. Thus, we propose to direct
that NERC modify FAC–002–0
accordingly.
357. Requirements R1.1 and R1.2
provide that an applicable entity
seeking to integrate generation,
transmission and end-user facilities
must perform an assessment that
includes: An evaluation of the reliability
impact of the new facilities and their
connections on the interconnected
transmission systems (R1.1) and
‘‘ensurance of compliance with NERC
Reliability Standards’’ and other
applicable criteria (R1.2). While we
agree with Alcoa that Requirements
R1.1 and R1.2 lack corresponding
metrics, we disagree that these
Requirements are overly-broad or openended. Nor do we read Requirement
R1.2 as suggesting that even a small
addition of facilities would compel an
entity to comply with all of the
Reliability Standards, which might not
otherwise apply. Rather, we believe that
the Requirements and existing Measures
set forth in FAC–002–0 are sufficiently
clear and objective to provide guidance
for compliance.
358. The Commission disagrees with
CenterPoint’s comments that because

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coordination is not readily auditable,
the Reliability Standard should be
eliminated. The Reliability Standard
specifies the assessments that must be
carried out to demonstrate that facility
connections meet reliability
performance requirements. Furthermore
the Reliability Standard specifies that
the assessment studies must be jointly
evaluated by the entities involved and
that evidence of such coordination shall
be provided. Coordination provides
assurance of a fair, equitable and
comprehensive Interconnection process,
which is the basis for open access and
is required to avoid adverse impacts on
reliability.
359. The Commission disagrees with
MEAG’s comment that the inclusion of
distribution providers is redundant and
unnecessary. The NERC definition
clearly identifies the role of the
distribution provider as providing the
‘‘wires’’ connecting the transmission
system to the end use customer. FAC–
002–0 has a reliability goal of avoiding
adverse impacts on Interconnections,
including a number of types of end-user
facilities. Because the distribution
provider has responsibility at the
interface between the transmission and
distribution system, it is proper that
FAC–002–0 include Requirements to
address those responsibilities.
360. The Commission agrees with the
ISO/RTO Council that the Reliability
Standard does not identify functional
entities responsible for specific tasks.
The Commission understands that the
roles and responsibilities of the
transmission planner and planning
authority in carrying out the tasks are in
accordance with the definitions in the
NERC glossary. Since the Commission
has previously approved the division of
responsibilities in various tariffs, the
exact delegation of individual tasks is
better placed in the procedures manuals
than in the Reliability Standard.
361. While the Commission has
identified concerns with regard to FAC–
002–0, we believe that the proposal
serves an important purpose in ensuring
that generator owners, transmission
owners and end-users meet facility
connection and performance
requirements. We note that the
Reliability Standards contains Measures
and Levels of Non-Compliance. Further,
the proposed Requirements set forth in
this Reliability Standard are sufficiently
clear and objective to provide guidance
for compliance.
362. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
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reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard FAC–002–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to FAC–002–0 that amends Requirement
R1.4 to require evaluation of system
performance under both normal and
contingency conditions by referencing
TPL–001 through TPL–003.
d. Transmission Vegetation
Management Program (FAC–003–1)
i. NERC Proposal
363. NERC stated that proposed
Reliability Standard FAC–003–1 is
designed to minimize transmission
outages from vegetation located on or
near transmission rights-of-way by
maintaining safe clearances between
transmission lines and vegetation, and
establish a system for uniform reporting
of vegetation-related transmission
outages. FAC–003–1 applies to
transmission lines operated at 200 kV or
higher voltage (and lower-voltage
transmission lines which have been
deemed critical to reliability by a
regional reliability organization). The
Reliability Standard requires each
transmission owner to have a
documented vegetation management
program in place, including records of
its implementation. Each program must
be designed for the geographical area
and specific design configurations of the
transmission owner’s system.
364. This Reliability Standard
requires a transmission owner to define
a schedule for and the type (aerial or
ground) of right-of-way vegetation
inspections. In addition, it requires a
transmission owner to determine and
document the minimum allowable
clearance between energized conductors
and vegetation before the next trimming,
and it specifically provides that
‘‘Transmission-Owner-specific
minimum clearance distances shall be
no less than those set forth in the
Institute of Electrical and Electronics
Engineers (IEEE) Standard 516–2003
(IEEE Guide for Maintenance Methods
on Energized Power Lines).’’ 162
365. Compliance with this standard is
measured against four Levels of NonCompliance. Levels 1 and 2 relate to
documentation. Level 3 non-compliance
occurs if a transmission owner reports
one incident of vegetation-related
outage in a calendar year due to
vegetation grow-ins from inside or
outside the right of way. If the
162 Standard

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transmission owner reports more than
one vegetation-related outage, then
Level 4 non-compliance has occurred.
ii. Staff Preliminary Assessment
366. Staff expressed concern that the
Reliability Standard does not designate
maximum allowable inspection
intervals but, instead, allows each
transmission owner to define its
inspection schedule and maintain its
own program. Thus, a transmission
owner cannot be faulted for the length
of its inspection interval, provided that
it has defined the schedule in its formal
program.
367. Staff also expressed concern with
the Reliability Standard’s development
of a minimum clearance, i.e., the
distance between a wire and the
vegetation around it, based on IEEE
standard 516–2003 that was developed
with the primary purpose of enabling
the performance of safe, energized line
maintenance.163 IEEE 516–2003
specifies a 2.45-foot clearance from a
live conductor for the 120 kV voltage
class.164 Staff noted that this clearance
is lower than that specified by relevant
U.S. safety codes such as the ANSI Z–
133 standard, which specifies 12-feet, 4inches as the approach distance for the
115 kV voltage class.165
368. Staff expressed concern that use
of the IEEE clearance provision as a
basis for minimum clearance may not be
appropriate, and adopting it for use with
regular maintenance practices in
vegetation management may be a
‘‘lowest common denominator’’
approach. In addition, use of IEEE
Standard 516–2003 could create the
unintended consequence that some
transmission owners that currently
maintain more stringent vegetation
management programs based on
standards such as the ANSI Z–133 may
relax their practices to meet the lessstringent minimum requirement set
forth in the NERC vegetation
management standard FAC–003–1. Staff
questioned whether the Reliability
Standard sufficiently addresses
Recommendation No. 16 of the Blackout
Report to establish ‘‘enforceable
standards for maintenance of electrical
clearances in right-of-way areas.’’ 166
163 Institute of Electrical and Electronics
Engineers, Inc. Standard 516–2003, IEEE Guide for
Maintenance Methods on Energized Power Lines at
1 (July 29, 2003) (IEEE 516–2003).
164 Id. at 20.
165 ANSI Z133, American National Standards
Institute Standard for Tree Care Operations—
Pruning, Trimming, Repairing, Maintaining and
Removing Trees, and Cutting Brush—Safety
Requirements.
166 Blackout Report at 154.

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iii. Comments
369. NERC contends that FAC–003–1
is an excellent standard that sets
appropriate requirements for managing
vegetation in transmission rights-ofway. NERC and other commenters
address four key issues: (1) Adequacy of
minimum clearances; (2) the need to
specify maximum inspection intervals;
(3) no vegetation-related outage can
occur without also violating the
proposed Reliability Standard; and (4)
cost impact of expanding the minimum
clearances.
370. Adequacy of minimum
clearances: NERC explains the adoption
of minimum clearance distances based
on the standard IEEE 516–2003 is
appropriate because, even though the
standard was originally developed for
live line workers, ‘‘its engineering basis
applies electric flashover physics that
apply to flashover conditions between
an energized conductor and a grounded
object, such as a tree.’’ 167 NERC adds
that the minimum clearances identified
in the standard are the ‘‘second’’
clearance requirement.168 In the first
instance, a transmission owner must
develop wider clearances when
accounting for vegetation growth, line
dynamics and other conditions between
the times of tree pruning.
371. Similar to NERC’s view on the
adequacy of minimum clearances,
several commenters argue that the IEEE
516–2003 standard is an appropriate
standard for use in FAC–003–1.169
Southern indicates that full compliance
with this standard would help to ensure
line reliability consistent with the
purposes of this standard and therefore
believes the use of the IEEE standard is
appropriate for use as a minimum
acceptable clearance in this context.
CenterPoint states that ‘‘clearance 2,’’
i.e., the minimum distance in FAC–003–
1, must be maintained under all rated
electrical operating conditions and must
167 NERC

Comments at 31.
1’’ is the clearance distance
between vegetation and a transmission line to be
achieved at the time of vegetation management
work, and ‘‘clearance 2’’ is the minimum clearance
distance between vegetation and a transmission line
to be achieved at all times. FAC–003–1 defines
‘‘clearance 2’’ in Requirement R1.2.2 as ‘‘The
Transmission Owner shall determine and document
specific radial clearances to be maintained between
vegetation and conductors under all rated electrical
operating conditions. These minimum clearance
distances are necessary to prevent flashover
between vegetation and conductors and will vary
due to such factors as altitude and operating
voltages. These Transmission Owner-specific
minimum clearance distances shall be no less than
those set forth in the [IEEE] Standard 516–2003
* * * and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tolls in
the Air Gap.’’
169 E.g., EEI, Mid-American, National Grid,
NRECA, PG&E, and Southern.

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consider additional clearance for the
dynamic movement of the transmission
conductors to avoid vegetation related
outages. According to CenterPoint, the
derived values from the IEEE table serve
only as a theoretical minimum for static
situations.
372. Conversely, ReliabilityFirst
submits that it agrees with staff’s
evaluation of standard FAC–003–1
regarding the appropriateness of using
the IEEE standard. SCE believes that the
adoption of IEEE 516–2003 in FAC–
003–1 to establish ‘‘specific radial
clearances to be maintained between
vegetation and conductors under all
rated electrical operating conditions’’ is
wholly inappropriate when determining
minimum tree-to-line clearances. SCE
states that no scientific evidence was
ever presented or cited during the NERC
standard development process that
demonstrated vegetation represented a
greater or equal flash-over hazard in
comparison to the human body (i.e., a
qualified electrical worker) when placed
in proximity to transmission lines. SCE
recommends that NERC establish a new
minimum clearance for transmission
lines operated at 200 kV and above and
that studies be conducted so that these
new minimum clearances be based on
real-world knowledge and line clearing
expertise, as opposed to simply
appropriating standards that were
designed for other situations.
373. Inspection Cycle: With regard to
a maximum allowable inspection cycle,
NERC believes FAC–003–1
appropriately provides discretion to
transmission owners to develop
vegetation inspection cycles appropriate
for their respective systems. Several
commenters argue that staff’s concern
that FAC–003–1 does not designate
maximum allowable inspection
intervals fails to recognize varying types
of vegetation, growth rates and climates
throughout North America.170 Some
commenters consider staff’s comment
on maximum allowable inspection
intervals as a ‘‘one size fits all’’
approach to vegetation management and
advise that such an approach to
inspection intervals could result in the
lowest common denominator among all
regions throughout the country or
unfairly punish or financially burden
certain regions. Allegheny proposes as
an alternative that maximum inspection
intervals could vary between Regional
Entities and notes that there might need
to be variations of the maximum

interval within a Regional Entity that is
geographically diverse.
374. Performance measure: NERC
states that no vegetation-related
transmission line outage can occur
without also being a violation of the
standard. NERC expresses the view that,
if such outages do occur, the
transmission owner has violated the
standard, and the solution is to engage
in compliance enforcement actions
rather than developing a wider margin
of clearance. Several commenters
concur with NERC on this point and
assert that staff’s concerns with regard
to maximum inspection intervals and
minimum clearances would not be an
issue if a vegetation management
standard measured and used
performance as a metric.171 Southern
points out that FAC–003–1 utilizes
outage reporting to measure the
effectiveness of an entity’s vegetation
management program and suggests that
the performance metric will expose the
standard’s shortcomings which can then
be addressed through a revision of the
standard.
375. Cost of compliance: Finally,
NERC and others express concern that
expanding the minimum clearances
could increase workload and costs yet
not provide any added reliability
benefit. Regarding the issue on
increased costs to maintain greater
minimum clearances versus reliability
benefits, EEI points out that ‘‘flexibility
written into the standard recognizes that
fixed clearance distances will not
provide stronger protection of the grid,
and are certain to cause significant
additional costs,’’ yet recognizes the
need to prevent cost-based incentives
which might drive the Reliability
Standard toward a lowest common
denominator.172
376. USDA Forest Service expresses
concern with regard to the manner in
which the requirements of EPAct 2005
are being applied. In particular, utilities
are submitting vegetation management
standards to the Commission for use on
National Forest System lands that were
not first approved by the USDA Forest
Service. It adds that it objects to any
process that allows a utility to set its
own new vegetation management
standards independently and to any
interpretation of EPAct 2005 that would
diminish the USDA Forest Service’s
authority to approve new vegetation
management standards on Forest
Service lands.

170 E.g., Allegheny, CenterPoint, EEI, MRO,
National Grid, NRECA, NYSPUC, SCE, and
Southern.

171 E.g., CenterPoint, National Grid, ISO/RTO
Council and Southern.
172 EEI Comments at 8.

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iv. Commission Proposal
377. Giving due weight to the
technical expertise of the ERO and with
the expectation that the Reliability
Standard will accomplish the purpose
represented to the Commission by the
ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard FAC–003–
1. In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
modify the Reliability Standard, as
discussed below.
(a) Adequacy of Minimum Clearances
378. NERC and others support the
proposed minimum ‘‘clearance 2’’
distances based on IEEE 516–2003 as
appropriate for use in vegetation
management. The Commission believes
that clearance distances need to exceed
IEEE 516–2003’s requirements in many
circumstances, but should never be less
than these requirements. The
Commission is concerned that the
application of the IEEE requirement
without consideration of specific
circumstances may result in flashovers,
and this possibility appears to be
addressed in IEEE 516–2003 and the
vegetation management standard.
Specifically, FAC–003–1 provides that a
transmission owner must ‘‘identify and
document clearances between
vegetation and [conductors] taking into
consideration transmission line voltage,
the effects of ambient temperature on
conductor sag under maximum design
loading, and the effects of wind
velocities on conductor sway.’’ 173 In
addition, the Reliability Standard
provides:

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The Transmission Owner shall determine
and document specific radial clearances to be
maintained between vegetation and
conductors under all rated electrical
operating conditions. These minimum
clearance distances are necessary to prevent
flashover between vegetation and conductors
and will vary due to such factors as altitude
and operating voltages.’’ 174

379. Consistent with the notion that
the minimum clearance may vary due to
various factors, NERC states that the
transmission owners must develop
wider clearances when accounting for
vegetation growth, line dynamics and
other conditions between the times of
tree pruning.175 In addition, IEEE 516–
2003 makes clear that the stated
minimum clearances are based on
‘‘standard’’ atmospheric conditions and
173 FAC–003–1,
174 FAC–003–1,

Requirement R1.2.
Requirement R1.2.2 (emphasis

added).
175 NERC Comments at 32.

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‘‘if standard atmospheric conditions do
not exist, extra care must be taken.’’ 176
380. NERC’s comments, IEEE 516–
2003, and the vegetation management
standard itself all make clear that the
minimum ‘‘clearance 2’’ distances based
on IEEE 516–2003 are adequate in some,
but not all, circumstances. The
minimum clearances that a transmission
owner must identify and document
depend on a variety of conditions
including, but not limited to,
transmission line voltage, temperature,
wind velocities, altitude. Accordingly,
we interpret the FAC–003–1 to require
trimming that is sufficient to prevent
outages due to vegetation management
practices under all applicable
conditions.177
381. In response to the USDA Forest
Service’s comments, we believe that any
potential issues regarding minimum
clearances on National Forest Service
lands should be dealt with on a case-bycase basis. The Commission seeks
comments whether another approach
would be more appropriate.
(b) Inspection Intervals
382. NERC and other commenters
believe FAC–003–1 appropriately
provides discretion to transmission
owners to develop vegetation inspection
cycles appropriate for their respective
systems. While the Commission
recognizes that some variation in
inspection cycles would be appropriate
based on climate and other factors, we
are concerned that the complete
discretion left to the transmission
owners in determining inspection cycles
limits the effectiveness of the Reliability
Standard.
383. While the Commission will not
dictate a specific minimum vegetation
inspection cycle, based on data
provided by transmission owners to the
Commission in 2004 as part of the
Commission’s vegetation management
survey, it appears that a one-year
vegetation inspection cycle is
reasonable.178 According to the
Vegetation Management Report, 76 of
176 IEEE 516–2003 at 20. Further, IEEE 516–2003
defines ‘‘standard atmospheric conditions’’ as
temperatures above freezing, wind less than 24
kilometer per hour, unsaturated air, normal
barometer, uncontaminated air, and clean and dry
insulators.’’
177 Nothing in this Reliability Standard should be
interpreted as preempting the authority and
responsibility of the states to set and enforce
minimum clearances, such as those delineated in
the National Electric Safety Code, to protect the
safety of the public.
178 The data provided in the survey was used to
prepare a report to Congress, Federal Energy
Regulatory Commission, Utility Vegetation
Management and Bulk Electric Reliability Report,
(September 7, 2004) (Vegetation Management
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161 entities surveyed conduct ground
inspections once a year.179 This
indicates that a one-year vegetation
inspection cycle is the ‘‘norm’’ for the
industry, but not a lowest common
denominator that sets a standard less
stringent than the industry practice.
While the Commission will not dictate
a minimum vegetation inspection cycle,
we do believe that it is important that
the ERO develop a minimum
requirement as a ‘‘backstop’’ to assure
that transmission owners conduct
inspections at a reasonable interval.
Accordingly, we propose to direct that
the ERO modify the Reliability Standard
to establish a minimum vegetation
inspection cycle.
384. Further, as mentioned above, the
Commission believes that some
variation to a continent-wide, one year
minimum cycle should be allowed due
to physical differences such as climate
and species of vegetation. Appropriate
variations may be determined on a
regional basis, with FAC–003–1
providing a continent-wide ‘‘backstop.’’
Alternatively, the continent-wide
standard could specify a one-year
minimum inspection cycle, and provide
that exemptions would be granted by
the ERO for legitimate physical
differences. The most appropriate
approach could be determined in the
ERO Reliability Standard development
process.
385. The applicability of FAC–003–1
currently states that it applies to all
transmission lines operated at 200 kV
and above and to any lower voltage
lines designated by the regional
reliability organization as critical to
reliability. The Commission is
concerned that the bright-line
applicability threshold of 200 kV will
exclude a significant number of
transmission lines that could impact
Bulk-Power System reliability. Although
the regional reliability organizations are
given discretion to designate lower
voltage lines under the proposed
Reliability Standard, we are concerned
that this approach will not result in the
inclusion of all transmission lines that
could impact Bulk Power System
reliability. Accordingly, the
Commission proposes to direct NERC to
change the applicability of FAC–003–1
so that it applies to Bulk-Power System
transmission lines that have an impact
of reliability as determined by the ERO.
386. While we have expressed some
concerns regarding FAC–003–1, we
179 Id. at 11. The Vegetation Management Report
indicates that 29 entities conduct ground
inspections semi-annually or more frequently, 37
entities inspect less frequently than annually, 12
inspect on an ‘‘as needed’’ basis, and seven entities
did not report on their inspection cycle.

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believe that it serves an important goal
of improving the reliability of the BulkPower System by preventing outages
from vegetation. Further, with our
interpretation above regarding
minimum clearances, the Commission
believes that the proposed Requirements
set forth in FAC–003–1 are sufficiently
clear and objective to provide guidance
for compliance.
387. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard FAC–003–
1. Further, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to FAC–
003–1 that: (1) The ERO develop a
minimum vegetation inspection cycle
that allows variation for physical
differences, as discussed above; and (2)
removes the applicability to
transmission lines operated at 200 kV
and above so that the Reliability
Standard applies to Bulk-Power System
transmission lines that have an impact
of reliability as determined by the ERO.
e. Methodologies for Determining
Electrical Facilities (FAC–004–0) and
Electrical Facility Ratings for System
Modeling (FAC–005–0)
388. NERC’s August 28, 2006
Supplemental Filing states that
Reliability Standards FAC–004–0 and
FAC–005–0 were filed for approval on
April 4, 2006, but have been superseded
by FAC–008–1 and FAC–009–1,
respectively. NERC has withdrawn its
request for approval of FAC–004–0 and
FAC–005–0. Thus, the Commission will
not address them in this notice of
proposed rulemaking.
f. Facility Ratings Methodology (FAC–
008–1)

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i. NERC Proposal
389. The stated purpose of FAC–008–
1 is to ensure that facility ratings used
in the reliable planning and operation of
the bulk electric system are determined
based on an established methodology. It
requires that each transmission owner
and generation owner develop a facility
rating methodology for their facilities,
which should consider manufacturing
data; design criteria (such as IEEE, ANSI
and other industry standards); ambient
conditions; operating limitations; and
other assumptions. This methodology is
to be made available to reliability
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transmission planners, and planning
authorities who have responsibility in
the same areas where the facilities are
located for inspection and technical
reviews.
ii. Staff Preliminary Assessment
390. Staff noted that this Reliability
Standard does not establish or require a
uniform or consistent set of
methodologies, which has resulted in
different ratings for the same equipment
under the same conditions in the same
region. Rather, it only requires an
equipment owner to document the
methodology it chooses to use. Thus,
staff was concerned that FAC–008–1
does not appear to address
Recommendation No. 27 of the Blackout
Report that NERC develop ‘‘clear,
unambiguous requirements for the
calculation of transmission line
ratings.’’ 180
iii. Comments
391. NERC comments that
strengthening the consistency of the
underlying assumptions and methods
used to determine the ratings of
facilities could improve the standard;
however, NERC cautions that a single,
uniform method for ratings calculations
will not be practical or effective. This
concern is echoed by ReliabilityFirst.
NERC explains that the rating of
facilities is very complex, beginning
with the fact that each physical device
has its own unique design criteria and
limitations, which are incorporated into
the device’s warranty. The facility
owner risks voiding the warranty or
damaging the physical device if it is
operated outside of the manufacturer
ratings. The second consideration is the
configuration of the equipment within
the power system. A facility owner
examines the equipments’ limitations
and uses engineering judgment to apply
a variety of assumptions and practices
in creating the design criteria for
operational facilities. NERC agrees that
it is at this step where practices could
be more consistent. However, it adds
that differences in assumptions and
practices arise from site-specific
characteristics such as climate
conditions, local equipment safety
codes, or life expectancy of the
equipment, and that when the standards
were developed, participants strongly
agreed that uniform methods were not
appropriate or feasible.
392. NERC points out that there are
trade-offs to uniform ratings methods.
Currently, a facility owner assumes a
business risk associated with the
assumptions used in the rating of
180 Blackout

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facilities because the facility owner has
invested in the equipment and is
responsible for maintaining the
warranty, the equipment’s performance,
and ultimately replacement costs. If
ratings are uniform and outside a
facility owner’s control, NERC questions
who would be responsible for
equipment failures. Uniform rating
methods might also lead to a reduction
in limits on facilities and, consequently,
reduced capacity of the transmission
network. Several commenters, including
NERC, agree with staff that regardless of
how ratings are developed, jointlyowned facilities must use the same
ratings.
393. Allegheny disagrees with staff’s
evaluation of standard FAC–008. It
comments that the industry does not
consider the absence of a standard
methodology for determining facility
ratings a threat to the reliability of the
transmission grid and that the
establishment of a uniform standard
will be a massive and costly
undertaking. Allegheny explains that,
historically, generator owners and
transmission owners rely on
manufacturer-provided equipment
ratings, in conjunction with their
respective business practices, to ensure
consistent documentation and
application of ratings to ensure
reliability. Further, monitoring by
regional organizations has also ensured
that generator and transmission owners’
practices address reliability concerns. In
light of this, Allegheny advocates that
staff’s recommendations not be adopted
without further demonstration that the
benefits justify the cost.
394. PG&E asserts that FAC–008–1
appropriately balances the need for
consistent facility ratings with the
realities of the transmission system and
that a single line rating methodology for
all of North America is neither practical
nor advisable. It explains that the
Reliability Standard properly places the
responsibility of determining facility
ratings with the facility owners. PG&E
believes the Reliability Standard’s
disclosure requirement safeguards
against manipulation of facility ratings.
395. Mid-American and MRO agree
that a consistent methodology should be
established for equipment rating. MidAmerican believes that the standard
should encourage a consistent
methodology for calculating equipment
ratings, ensure transmission customers
of nondiscriminatory treatment without
being overly burdensome to the facility
owner, and must address all factors that
affect equipment ratings. However, MidAmerican does not support an overlyprescriptive standard. It suggests that
staff’s concerns should be directed at

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ensuring consistent methodologies for
rating development, however, points out
that a consistent methodology may still
result in differing numerical ratings due
to differing ambient temperatures, sag
conditions, etc., that may exist in
differing regions. While supporting
staff’s recommendation for a consistent
methodology, MRO disagrees with
staff’s approach. Transmission owners
should be able to set facility ratings as
they see fit, provided the rating is
communicated to others and the
transmission owners operate with the
same rating.
396. National Grid comments that it
supports some measure of
standardization of equipment rating
methodologies. It explains that, ‘‘if left
entirely to the asset owners, the lack of
uniform equipment rating
methodologies leaves open the
possibility in some circumstances that
the determination of facility ratings can
be used by an asset owner to gain a
market edge over other market
participants that do not own assets.’’ 181
National Grid encourages the
standardization of facility ratings only at
a conceptual level, though not
necessarily the standardization of
specific parameters, recognizing
regional climatic and topological
conditions.
397. CenterPoint contends that
Reliability Standards FAC–004–0, FAC–
005–0, FAC–008–1 and FAC–009–1 are
not necessary and should be rejected. It
explains that Blackout Report
Recommendation No. 27 does not
require a uniform set of methodologies
for rating facilities, but instead only
recommends that there be clear,
unambiguous requirements to rate
transmission lines. According to
CenterPoint, most if not all utilities
follow a standard IEEE method for
rating transmission lines.
398. The Valley Group proposes that
the fastest and most efficient way to
fulfill Blackout Report Recommendation
No. 27 would be the adoption of the
principles of the International Council
on Large Electric Systems (CIGRE)/IEEE
Guide and the necessary procedures for
enforcement. The Valley Group cites
survey data indicating that a large
percentage of utilities have increased
their facility ratings by changing certain
ratings assumptions, most commonly by
increasing the assumed wind speed. It
views this as a dangerous trend because
system loads have generally increased
during the same period. It also sees the
regional adoption of assumptions being
based on utilities with the least
conservative practices, leading to a
181 National

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‘‘lowest common denominator’’ result.
To correct this problem, the Valley
Group encourages adoption of IEEE/
CIGRE guidelines for selection of
weather parameters.182
399. Alcoa agrees with staff’s
evaluation of the facility Reliability
Standards. It adds that, without a clear
set of straightforward methodologies for
facility ratings, the proposed
documentation requirements are unduly
burdensome. Alcoa suggests that the
ERO propose methodologies that
consider the relative importance to the
reliability of the Bulk-Power System, as
well as the ability of the owner of the
facilities to pass on the costs incurred to
enhance reliability to those receiving
the benefit.
iv. Commission Proposal
400. The Commission proposes to
approve FAC–008–1 as mandatory and
enforceable. In addition, we propose
directing that NERC develop
modifications to the Reliability
Standard, as discussed below.
401. The Commission agrees with
NERC and others that the assumptions
used in the methodologies can not be
standardized. The assumptions are
essentially input variables into rating
methodologies used to convert the input
into the normal and emergency ratings
of the facilities. Owners will use the
actual topology and substation
arrangement of the facilities in
configuring equipment for facility
ratings. There should be different input
variables such as the ambient
temperatures in Texas as compared to
Maine. Thus, we are not proposing to
require a ‘‘uniform method of ratings
calculation,’’ which would standardize
the input assumptions in the formula for
calculating ratings.
402. On the other hand, the
Commission disagrees with MRO that
transmission owners ‘‘should set the
rating as they see fit, provided that
everyone knows what the rating is and
that rating is used for all purposes
including the Transmission Owner’s use
of the facilities.’’ 183 As explained by
National Grid, allowing facility owners
to set ratings ‘‘as they see fit’’ could
result in the use of a facility rating
determination to gain a competitive
advantage over other market
participants that do not own assets. This
could harm the reliability of the
transmission grid and can also impact
competition as described by National
182 The Valley Group cites a CIGRE Technical
Brochure entitled Guide for Selection of Weather
Parameters for Overhead Bare Conductor Ratings
published in August 2006 and a CIGRE/IEEE
Tutorial, which was presented in June 2006.
183 MRO Comments at 8.

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Grid. Likewise, the Valley Group raises
legitimate concerns about manipulation
of the assumptions, in particular wind
speed, demonstrating the need not only
for uniformity, but for oversight as well.
403. The Commission believes that, to
address the concerns of National Grid,
Valley Group and others, the Reliability
Standard could be improved in two
ways. First, we propose that the
different assumptions that are the basis
for the input variables should be
documented and made available for
review by other users, owners and
operators of the Bulk-Power System.
Currently, only a subset of functional
entities responsible for the facilities in
a specific area are able to view this
information. The added transparency
that we propose would allow customers,
regulators and other affected users,
owners and operators of the Bulk-Power
System to understand how a facility
owner sets its facility ratings.
404. Second, asset owners use various
methods for calculating ratings that are
widely accepted throughout the
industry, such as IEEE and CIGRE, to
calculate transmission line conductor
ratings. While not proposing to mandate
a particular methodology, we do
propose that the methodology chosen by
a facility owner be consistent with
industry standards developed through
an open process such as IEEE or CIGRE.
405. Further, consistent with NERC’s
comments,184 the Commission proposes
that the limiting component(s) be
identified and that the increase in rating
based on the next limiting component(s)
be defined for all critical facilities,
including facilities that limit TTC, limit
delivery of generation to load, or bottle
generation. This would provide
additional transparency and sufficient
information so that the most cost
effective solutions to increase facility
ratings can be identified. For example,
if a specific transmission line is limited
by the relay settings or protective relay
system, ordinarily the line could be ‘‘up
rated’’ for a relatively modest cost. As a
second example, if a line is limited by
the sag of one particular span,
modifying the tension in that span, even
if it requires reinforcing a few towers,
may result in significant increases in
capability at relatively low cost. Such
information would be useful to users of
the Bulk-Power System and to the
Commission.
406. CenterPoint has not provided a
compelling reason for us to reject this
Reliability Standard. Assuming
CenterPoint is correct that most, if not
all, utilities follow a standard method
for rating transmission lines, that fact
184 See

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does not obviate the need for mandatory
and enforceable Reliability Standards
that require clear, ambiguous
requirements to rate transmission lines.
Moreover, industry use of a standard
line rating method may be a result of the
Reliability Standard, which requires
facility owners to consider industry
rating practices such as IEEE. Moreover,
the Reliability Standards include ratings
for all facilities, not just transmission
lines.
407. FAC–008–1 makes considerable
progress in addressing Blackout Report
Recommendation No. 27, which as
noted above recommends that NERC
develop clear and unambiguous
requirements for the calculation of
transmission line ratings. While the
Commission has identified ways to
improve and strengthen this Reliability
Standard, we believe that the proposal
serves an important purpose in ensuring
that facility ratings are determined
based on an established methodology.
Further, the Commission believes that
the proposed Requirements set forth in
FAC–008–1 are sufficiently clear and
objective to provide guidance for
compliance.
408. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard FAC–008–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to FAC–008–1 that requires
transmission and generation facility
owners to: (1) Document underlying
assumptions and methods used to
determine normal and emergency
facility ratings; and (2) develop facility
ratings consistent with industry
standards developed through an open
process such as IEEE or CIGRE; and (3)
identify the limiting component(s) and
define for all critical facilities the
increase in rating based on the next
limiting component(s).
g. Establish and Communicate Facility
Ratings (FAC–009–1)
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i. NERC Proposal
409. The stated Purpose of FAC–009–
1 is to ensure that facility ratings are
determined based on an established
methodology. It requires each
transmission owner and generation
owner to establish facility ratings
consistent with their associated facility

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ratings methodology and provide those
ratings to their reliability coordinator,
transmission operator, transmission
planner, and planning authority.
ii. Staff Preliminary Assessment
410. The Staff Preliminary
Assessment did not identify any issues
related to this Reliability Standard.
iii. Comments
411. ReliabilityFirst agrees with staff’s
evaluation that FAC–009–1 does not
contain any substantive issues.
iv. Commission Proposal
412. FAC–009–1 serves an important
reliability purpose of ensuring that
facility ratings are determined based on
an established methodology. Further,
the proposed Requirements set forth in
FAC–009–1 are sufficiently clear and
objective to provide guidance for
compliance. Accordingly, the
Commission proposes to approve
Reliability Standard FAC–009–1
(Establish and Communicate Facility
Ratings) as just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
h. Transfer Capability Methodology
(FAC–012–1)
i. NERC Proposal
413. Proposed Reliability Standard
FAC–012–1 requires each reliability
coordinator and planning authority to
document their methodology used to
develop inter-regional and intra-regional
transfer capabilities. This methodology
must describe how it addresses
transmission topology, system demand,
generation dispatch, and use of
projected and existing commitment of
transmission.
ii. Staff Preliminary Assessment
414. Staff noted that a move toward
standardization of the inter-regional and
intra-regional transfer capability may be
desirable to ensure an adequate level of
reliability and minimize undue negative
impact on competition.
iii. Comments
415. Responding to staff’s suggested
move toward standardization, MRO
comments that the Reliability Standards
should recognize the differences in
geographical diversity, as well as
relative population size, to maintain
reliability. A single approach is
desirable, but it should provide the
flexibility to adjust for technical
realities within a given part of the
Eastern Interconnection. It explains that
the assumptions underlying
methodologies for determining interregional and intra-regional transfer

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capabilities may vary for different
regions of the Eastern Interconnection
due to geography, system design,
weather, or state-specific requirements.
Transparency in the approach and
assumptions is essential.
416. PG&E comments that the
inherent differences in the development
of the transmission infrastructure
between the Eastern Interconnection
and the Western Interconnection weigh
against the imposition of a single
methodology. Because transmission
lines tend to be located in common
corridors in the Western
Interconnection, efficiency and
reliability are maximized by transfer
capabilities calculated with
consideration of selected multiple
contingencies to account for the
multiplicity of potential credible events.
417. CenterPoint proposes that FAC–
012–1 be consolidated with FAC–013–1.
Further, it advocates that, because the
ERCOT region operates as a single
control area and thus does not have
transfers between control areas, the
NERC transfer capability methodology is
not used, nor should it be.
iv. Commission Proposal
418. As the methodology to calculate
transfer capability used by a reliability
coordinator or planning authority has
not been submitted to the Commission,
it is not possible to determine at this
time whether FAC–012–1 satisfies the
statutory requirement that a proposed
Reliability Standard be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.’’ Accordingly, the Commission
will not propose to accept or remand
this Reliability Standard, until the
regional procedures are submitted. In
the interim, compliance with FAC–012–
1 should continue on its current basis,
and the Commission considers
compliance with the Reliability
Standard to be a matter of good utility
practice.
419. Although we do not propose any
action with regard to FAC–012–1 at this
time, we address comments and our
additional concerns regarding this
Reliability Standard below.
420. We agree with MRO and PG&E
that different regions or
Interconnections may have different
geography, population size, or
transmission structure that necessitate
different approaches to transfer
capability, and we have noted that the
Requirement R1.3 addresses issues such
as transmission system topology and
current and projected use of
transmission system for reliability
margin but not for transfer capability
calculation. FAC–012–1 only requires

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that the regional reliability organization
provide documentation on transfer
capability methodology and provide this
documentation to entities such as
transmission planner, planning
authority, reliability coordinator, and
transmission operator. The Reliability
Standard does not contain clear
requirements on how transfer capability
should be calculated, which has
resulted in diverse interpretations of
transfer capability and the development
of various calculation methodologies.185
We believe that this Reliability Standard
should, as a minimum, provide a
framework for the transfer capability
calculation methodology including data
inputs, and modeling assumptions. We
seek comments on the most efficient
way to make the above information
transparent for all participants.
421. With regard to CenterPoint’s
comment, while FAC–012, which
pertains to the documentation of
transfer capability methodologies, and
FAC–013, which pertains to the
establishment of transfer capabilities
consistent with the methodology, are
related, we leave it to NERC’s discretion
whether they should be consolidated.
As we have mentioned elsewhere,
CenterPoint’s suggestion that the
Reliability Standard not apply to the
ERCOT region must be submitted by
NERC as a regional difference.

regional reliability organization), and a
planning authority (as required by its
regional reliability organization). The
Commission believes that the Reliability
Standard should be applicable to all
Reliability Coordinators. A planning
authority may also have a role in
determining transfer capabilities,
however, the regional reliability
organization should not be the entity
that makes this determination.
426. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard FAC–013–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to FAC–013–1 that: (1) Makes it
applicable to all reliability coordinators;
and (2) removes the regional reliability
organization as the entity that
determines whether a planning
authority has a role in determining
transfer capabilities.

i. Establish and Communicate Transfer
Capability (FAC–013–1)

a. Overview

i. NERC Proposal
422. Proposed Reliability Standard
FAC–013–1 requires each reliability
coordinator and planning authority to
calculate transfer capabilities consistent
with its transfer capability methodology
and provide those capabilities to its
transmission operators, transmission
service providers, and planning
authorities.
ii. Staff Preliminary Assessment
423. The Staff Preliminary
Assessment did not identify any issues
related to this Reliability Standard.

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iii. Comments
424. ReliabilityFirst agrees with staff’s
evaluation that FAC–013–1 does not
contain any substantive issues.
iv. Commission Proposal
425. The Commission’s concern about
this Reliability Standard is related to the
applicability. The Reliability Standard
currently states that it is applicable to a
reliability coordinator (as required by its

6. INT: Interchange Scheduling and
Coordination

427. The Interchange Scheduling and
Coordination (INT) group of Reliability
Standards addresses the process of
Interchange Transactions, which occur
when electricity is purchased and
transmitted from a seller to a buyer
across the power grid.186 Specific
information regarding each transaction
must be identified in an electronic label,
known as a ‘‘Tag,’’ which is used by an
affected reliability coordinator,
transmission service provider or
balancing authority to assess the
transaction for reliability impacts. In
addition, communication, submission,
assessment and approval of a Tag must
be completed for reliability
consideration before implementation of
the transaction.
428. In its April 4, 2006 Petition,
NERC submitted four Version 0
interchange Reliability Standards, INT–
001–0 through INT–004–0. In its August
28, 2006 Supplemental Filing, NERC
submitted nine Version 1 proposed
Reliability Standards in the INT
186 NERC

185 Path rating process in WECC and various
regional transfer capability methodologies in the
Eastern interconnection.

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glossary at 8 defines ‘‘Transaction’’ as
‘‘[a]n agreement to transfer energy from a seller to
a buyer that crosses one or more Balancing
Authority Area boundaries.’’

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64813

group.187 Reliability Standards INT–
001–1, INT–003–1 and INT–004–1
replace the corresponding Version 0
standards although, as discussed later
on, the language of some Requirements
have been modified and other
Requirements have been transferred
elsewhere. NERC states that Reliability
Standard INT–002–0 is being retired,
effective January 1, 2007 and asked that
it be withdrawn for Commission review.
Reliability Standards INT–005–1
through INT–010–1 are new to the
Version 1 Reliability Standards.
i. General Comments
429. CenterPoint comments that the
INT group of proposed Reliability
Standards should be rejected because
Reliability Standards that attempt to
create auditable requirements to
measure ‘‘coordination’’ cannot
realistically be implemented and are
unnecessary appendages to Reliability
Standards addressing the actual goal of
ensuring reliable operation. CenterPoint
also contends that, if the Commission
approves the INT group of Reliability
Standards, ERCOT should be explicitly
exempted from them because
interchange tagging is not used in
ERCOT.
430. ReliabilityFirst comments
generally on the INT group of Reliability
Standards. It states that the
development of missing compliance
elements by NERC’s drafting team must
be expedited and that it may be
necessary to supplement the team with
additional experts if it is necessary to
expand and/or detail requirements in
these Reliability Standards.
ii. Commission Proposal
431. Order No. 672 explains that a
Reliability Standard must be designed to
achieve a specified reliability goal.188
The goal of the INT group of Reliability
Standards is not simply to measure
coordination as CenterPoint contends.
Rather, these Reliability Standards are
intended to ensure that uses of the BulkPower System are known to operating
entities and reliability coordinators
sufficiently in advance to permit them
to evaluate reliability impacts and
curtail transactions in the event system
parameters approach their operating
limits.189 In our view, the INT group of
Reliability Standards is designed to
achieve a specified goal that is
important to maintaining Bulk-Power
System reliability. Accordingly, the
Commission disagrees with CenterPoint
187 INT–001–1, INT–003–1, INT–004–1, INT–005–
1, INT–006–1, INT–007–1, INT–008–1, INT–009–1,
INT–010–1.
188 Order No. 672 at P 324.
189 NERC Petition at 40–41.

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that the INT group of Reliability
Standards should be rejected.
432. With regard to CenterPoint’s
suggestion that ERCOT be explicitly
exempted from the INT group of
Reliability Standards, we note that
NERC has not proposed such an
exemption as a regional difference.
Order No. 672 makes clear that a
proposed Reliability Standard,
including a modification or regional
difference to a Reliability Standard,
must be submitted by the ERO to the
Commission for our consideration.190
Accordingly, we will not consider such
an exemption unless submitted by
NERC for our review.
433. With regard to ReliabilityFirst’s
comment, we agree that the
development of missing compliance
elements is an important priority and
note that NERC has stated that it plans
to submit a filing in November 2006 that
will include many such missing
compliance elements. NERC staffing of
the team assigned to develop missing
compliance elements is a matter beyond
the scope of this proceeding.
b. Interchange Information (INT–001–1)
i. NERC Proposal
434. NERC states that the purpose of
INT–001–1 is to ensure that interchange
information is submitted to the
reliability analysis service identified by
NERC.191 Proposed Reliability Standard
INT–001–1 applies to purchasing-selling
entities and balancing authorities. It
specifies two Requirements that focus
primarily on establishing who has
responsibility in various situations for
submitting the Interchange information,
previously known as transaction tag
data, to the reliability analysis service
identified by NERC.192 The
Requirements apply to all dynamic
schedules, delivery from a jointly
owned generator and bilateral
inadvertent interchange payback.
ii. Staff Preliminary Assessment
435. Staff noted that INT–001–0 has
only one Measure and no Levels of NonCompliance. The Version 1 standard,
INT–001–1, would delete the one
Measure and, thus, would contain no
Measures or Levels of Non-Compliance.

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iii. Comments
436. ISO/RTO Council generally
agrees with staff that INT–001–0 lacks
sufficient compliance measures.
190 Order

No. 672 at P 249.
the reliability analysis service used
by NERC is the Interchange Distribution Calculator.
192 NERC’s Glossary of Terms adopted by NERC’s
Board of Trustees on August 2, 2006 defines
Interchange as ‘‘Energy transfers that cross
Balancing Authority boundaries.’’
191 Currently,

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Allegheny, in contrast, comments that
tagging deadlines within the Reliability
Standard provide an adequate measure
of compliance.
iv. Commission Proposal
437. The Commission proposes to
approve INT–001–1 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
438. Requirement R1.2 in INT–001–0
(the Version 0 standard) requires data
submission on all point-to-point
transfers entirely within a balancing
authority area, including ‘‘all
grandfathered and ’non-Order 888’
Point-to-Point Transmission Service.’’
This Requirement to submit data for
grandfathered and non-Order 888 pointto-point transmission service is not
included in INT–001–1 or any other
Version 1 Reliability Standard in the
INT group. These transactions, if not
reported, will create a gap in reliability
assessment and transaction curtailment
provisions and may result in adverse
impact on reliable operation of the
Interconnection. Therefore, the
Commission proposes to direct that
NERC retain this important
Requirement.
439. Requirements R1.1, R3, R4 and
R5 of INT–001–0, which relate to the
timing and content of e-tags, have been
deleted in the Version 1 Reliability
Standard. NERC indicates that these
Requirements are actually business
practices and that they will be included
in the next version of NAESB Business
Practices.193 Without prejudging any
future proceeding regarding NAESB
business practices, we find acceptable
NERC’s explanation that the deleted
Requirements are business practices,
and we propose to approve INT–001–1
with the deletion of Requirements R1.1,
R3, R4 and R5. However, the
Commission notes that NAESB has not
at this time filed these e-tagging
requirements as part of its business
practices. If, at the time of the final rule,
no such business practice has been
submitted, the Commission may
reinstate these Requirements as part of
the final rule. In the future, to ensure
that there is not a gap in Reliability
Standards or business practices, the
Commission expects filings from NERC
and NAESB be coordinated to allow for
the seamless transfer of Requirements
from Reliability Standards to Business
Practices.
193 See NERC Implementation Plan for Coordinate
Interchange Standards INT–005 through INT–010
(December 15, 2005) at 2–3.

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440. With regard to Allegheny’s
comments, we believe that all
Reliability Standards will benefit from
Measures and Levels of NonCompliance. Further, as mentioned
above, the tagging deadlines which
Allegheny believes provides an
adequate measure of compliance have
been deleted and will be incorporated
by NAESB as business practices.
441. While the Commission has
identified concerns with regard to INT–
001–1, it serves an important purpose in
ensuring that responsible entities have
the information they need to assess the
reliability impact of an interchange
transaction. While NERC should
provide Measures and Levels of NonCompliance, the Requirements set forth
in INT–001–1 are sufficiently clear and
objective as to provide guidance for
compliance.
442. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard INT–001–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC submit a modification to INT–
001–1 that: (1) Includes Measures and
Levels of Non-Compliance; and (2)
includes a Requirement that interchange
information must be submitted for all
point-to-point transfers entirely within a
balancing authority area, including all
grandfathered and ‘‘non-Order No. 888’’
transfers.
c. Regional Difference to INT–001–1 and
INT–004–1: WECC Tagging Dynamic
Schedules and Inadvertent Payback
i. NERC Proposal
443. NERC states that WECC has a
regional variance that exempts tagging
dynamic schedules and inadvertent
payback. The waiver request included
with the proposed Reliability Standards
explains that tagging requirements
simply do not apply to operations in the
Western Interconnection. Also, a tagging
requirement for dynamic schedules
would create a burden for scheduling
entities and not provide a substantial
benefit. NERC explains that control
areas and transmission providers have
real-time scheduling information on
dynamic schedules and that unilateral

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inadvertent payback is not allowed in
the WECC.194
ii. Commission Proposal
444. As discussed earlier, in Order
No. 672, the Commission stressed that
uniformity of Reliability Standards
should be the goal and practice, ‘‘the
rule rather than the exception.’’ 195 The
absence of a tagging requirement for
dynamic schedules in WECC is,
therefore, a matter of concern to us.
However, the Commission understands
that WECC currently is developing a
tagging requirement for dynamic
schedules.196 The Commission seeks
information from NERC on the status of
the proposed tagging requirement, the
time frame for its development, its
consistency with INT–001–1 and INT–
004–1, and whether the need for the
current waiver will be obviated when
the tagging requirements become
effective. The Commission will not
approve or remand the waiver until
NERC submits this information. The
Commission will consider any regional
differences contained in proposed
WECC tagging requirement for dynamic
schedules when it is submitted by NERC
for Commission review.
d. Regional Difference to INT–001–1
and INT–003–1: MISO Energy Flow
Information

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i. NERC Proposal
445. NERC states that a regional
difference is necessary to allow MISO to
provide market flow information in lieu
of tagging intra-market flows among its
member balancing authorities. The
waiver request included with the
proposed Reliability Standards seeks
specific provisions to accommodate a
multi-control area energy market.
According to the waiver request, the
MISO energy flow information waiver is
needed to realize the benefits of
locational marginal pricing within
MISO while increasing the level of
granularity of information provided to
the NERC TLR Process. The waiver
request text states that it is understood
that the level of granularity of
information provided to reliability
coordinators must not be reduced or
reliability will be negatively
impacted.197 The waiver text includes a
condition specifying that the ‘‘Midwest
194 Waiver Request—Tagging Dynamic Schedules
and Inadvertent Payback, Approved November 21,
2002. NERC Petition, Exhibit A.
195 Order No. 672 at P 290.
196 Information on this development can be found
at: http://www.wecc.biz/index.php?module=pn
Forum&func=viewtopic&topic=394.
197 Waiver Request—Energy Flow Information,
Approved July 16, 2003. (Attached to NERC’s
proposed Reliability Standards).

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ISO must provide equivalent
information to Reliability Authorities as
would be extracted from a transaction
tag.’’
ii. Commission Proposal
446. Order No. 672 explains that
‘‘uniformity of Reliability Standards
should be the goal and the practice, the
rule rather than the
exception.’’ 198However, the
Commission has stated that, as a general
matter, regional differences are
permissible if they are either more
stringent than the continent-wide
Reliability Standard, or if they are
necessitated by a physical difference in
the Bulk-Power System.199 Regional
differences must still be just, reasonable,
not unduly discriminatory or
preferential and in the public
interest.200
447. Based on the information
provided by NERC, the proposed
regional difference for the INT
Reliability Standards is necessary to
accommodate MISO’s Commissionapproved, multi-control area energy
market.201 Thus, we believe that the
regional difference is appropriate as it is
more stringent than the continent-wide
Reliability Standard and otherwise
satisfies the statutory standard for
approval of a Reliability Standard.
448. Accordingly, the Commission
proposes to approve the regional
difference.
e. Interchange Transaction
Implementation (INT–003–1)
i. NERC Proposal
449. NERC states that the purpose of
the INT–003–1 is to ensure that
balancing authorities confirm
interchange schedules with adjacent
balancing authorities prior to
implementing the schedules in their
area control error equations. The
proposed Reliability Standard applies to
balancing authorities. INT–003–1
contains one Requirement that focuses
on ensuring that a sending balancing
authority confirms interchange
schedules with the receiving balancing
authority prior to implementing the
schedules in its control area. The
proposed Reliability Standard also
requires that, for the instances where a
high voltage direct current (HVDC) tie is
on the scheduling path, both sending
and receiving balancing authorities have
198 Order
199 Id.

No. 672 at P 290.
at 291.

200 Id.
201 See Midwest Independent Transmission
System Operator, Inc., 102 FERC ¶ 61,196 at P 38
(2003).

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64815

to coordinate with the operator of the
HVDC tie.
450. NERC indicates that it will
modify this proposed Reliability
Standard to address the lack of
Measures and Levels of NonCompliance and resubmit the proposal
for Commission approval in November
2006.
ii. Staff Preliminary Assessment
451. Staff noted in its Staff
Preliminary Assessment that INT–003–0
contains no Measures or Levels of NonCompliance. This comment applies
equally to INT–003–1.
iii. Commission Proposal
452. The Commission notes that
Requirement R1.1.3 addressing ramp
starting time and duration in INT–003–
0 is removed from INT–003–1, and will
be included as a NAESB business
practice, whereas Requirement R1.3
addressing interchange schedules
crossing an interconnection boundary is
now included in the new INT–009–1. In
addition, Requirements R2, R3 and R4
in INT–003–0 addressing
implementation requirements and
responsibilities on the balancing
authorities are transferred to INT–009–
1. Requirement R5 stipulating that
balancing authorities in implementing
interchange schedule do not knowingly
cause other system to violate operating
criteria is now retired. Requirement R6
on the maximum limit on the net
interchange schedule is replaced with
R1.2 in the new INT–006–1.
453. As noted above, INT–003–1 lacks
Measures and Levels of NonCompliance. While it is important to
develop Measures and Levels of NonCompliance, the Commission believes
that INT–003–1 serves an important
purpose in requiring receiving and
sending balancing authorities to confirm
and agree on the interchange schedules.
Further, we believe that the
Requirements set forth in INT–003–1 are
sufficiently clear and objective to
provide appropriate guidance for
compliance.
454. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard INT–003–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing NERC
to submit a modified Reliability

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Standard that includes Measures and
Levels of Non-Compliance.

transactions within and between
RTOs.205

Filing, and no comments were
submitted regarding it.

f. Regional Differences to INT–003–1:
MISO/SPP Scheduling Agent and MISO
Enhanced Scheduling Agent

ii. Commission Proposal

iv. Commission Proposal

457. The Commission ruled in Order
No. 672 that, as a general matter, the
following types of regional differences
in Reliability Standards would be
acceptable: (1) a regional difference that
is more stringent than the continentwide Reliability Standard, including a
regional difference that addresses
matters that the continent-wide
Reliability Standard does not; and (2) a
regional Reliability Standard that is
necessitated by a physical difference in
the Bulk-Power System.206
458. Based on the information
provided by NERC, the proposed
regional differences for the INT
Reliability Standard will provide
administrative efficiency, and equal or
greater amounts of information to the
appropriate entities as required in
MISO’s Commission-approved multicontrol area energy market.207 Thus, we
believe that the proposed regional
differences meet the legal standard for
approval as well as the first criteria
discussed above for a regional
difference.
459. Accordingly, for the reasons set
forth above, the Commission proposes
to approve these two additional regional
differences.

463. The Commission notes that
Requirement R1 in INT–004–1
providing procedures to modify
interchange schedules to address
reliability events are replaced with
Requirements R1, R2 and R3 in the new
INT–010–1. Requirement R2 which
applies to generator operators or load
serving entities for requesting to modify
an interchange transaction due to loss of
generation or load is replaced with
Requirements in INT–005–1 through
INT–010–1.
464. The Commission believes that
Levels of Non-Compliance should be
included.
465. INT–004–1 contains a regional
variance from WECC that exempts
tagging dynamic schedules and
inadvertent payback. This is discussed
above in more detail. The Commission
proposes to leave pending the WECC
regional difference until NERC files a
new regional difference.
466. While the Commission has
identified concerns with regard to INT–
004–1, this proposed Reliability
Standard serves an important purpose
by setting thresholds on changes in
dynamic schedules for which modified
interchange data must be submitted for
reliability assessment. Further, the
Requirements set forth in INT–004–1 are
sufficiently clear and objective to
provide guidance for compliance.
467. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard INT–004–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing NERC
to submit a modification to INT–004–1
that includes Levels of NonCompliance.

i. NERC Proposal
455. The MISO/SPP Scheduling Agent
Waiver dated November 21, 2002
creates variances from this proposed
Reliability Standard for MISO/SPP that
permits a market participant to utilize a
scheduling agent to prepare a
transaction Tag on its behalf.202 The
scheduling agent is a single point of
contact for all external, nonparticipating control areas or other
scheduling agents with respect to
scheduling interchange into, out of, or
through the RTO to which the variance
applies. The variance document
explains that the variance is needed to
implement a proposed RTO scheduling
process to meet the RTO obligations
under Order No. 2000, simplify
transaction information requirements
for market participants, reduce the
number of parties with which control
area operators must communicate, and
provide a common means to tag
transactions within and between RTOs.
It also specifies that the specific
scheduling processes implemented
between participating control areas are
internalized and transparent to the
market, but that it has no reliability
implications and will not violate any
reliability criteria.203 The Commission
has issued orders authorizing use of
these practices by MISO.204
456. The MISO Enhanced Scheduling
Agent Waiver dated July 16, 2003
creates a variance from INT–003–1 for
MISO that permits an enhanced single
point of contact scheduling agent.
Again, the variance document explains
that the variance is needed to
implement a proposed RTO scheduling
process to meet the RTO obligations
under Order No. 2000, simplify
transaction information requirements
for market participants, reduce the
number of parties with which control
area operators must communicate, and
provide a common means to tag

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202 NERC

has proposed three regional differences
for INT–003–1 that would apply to MISO. One
regional difference was addressed above as it also
related to Reliability Standard INT–001–1. The
remaining two are discussed here.
203 Waiver Request—Scheduling Agent,
Approved November 21, 2002. NERC Petition,
Exhibit A.
204 Midwest Independent Transmission System
Operator, Inc., et al., 108 FERC ¶ 61,163 at P 100
(2004).

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g. Dynamic Interchange Transaction
Modifications (INT–004–1)
i. NERC Proposal
460. NERC states that the purpose of
INT–004–1 is to ensure that dynamic
transfers are adequately tagged to be
able to determine their reliability
impact. It requires the sink balancing
authority, i.e., the balancing authority
responsible for the area where the load
or end-user is located, to communicate
any change in the transaction. It also
requires the updating of a Tag for
dynamic schedules, i.e., transactions
that vary from within an hour. INT–
004–1 does not identify Levels of NonCompliance.
ii. Staff Preliminary Assessment
461. No concerns were raised in the
Staff Preliminary Assessment.
iii. Comments
462. INT–004–1 was included in
NERC’s August 28, 2006 Supplemental
205 Waiver Request—Enhanced Scheduling Agent,
Approved November 16, 2003. ERC Petition,
Exhibit A.
206 Order No. 672 at P 291.
207 See Midwest Independent Transmission
System Operator, Inc., 102 FERC ¶ 61,196 at P 38
(2003).

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h. Interchange Authority Distributes
Arranged Interchange (INT–005–1)
i. NERC Proposal
468. INT–005–1, submitted with
NERC’s August 28, 2006 Supplemental
Filing, ensures the implementation of
interchange between source and sink
balancing authorities and the
interchange information is distributed
by an interchange authority to the
relevant entities for reliability

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assessments. INT–005–1 is applicable to
the ‘‘interchange authority.’’ 208
ii. Commission Proposal
469. The Commission is satisfied that
the Requirements of the Reliability
Standard are appropriate to ensure that
interchange information is distributed
and available for reliability assessment
prior to its implementation. However,
we are concerned regarding the
applicability of INT–005–1 to the
interchange authority. It is not clear
from NERC’s definition whether an
interchange authority is a user, owner or
operator of the Bulk-Power System, or
what types of entities would be eligible
to perform such a function. Therefore,
the Commission requests that NERC
provide additional information
regarding the role of the interchange
authority so that the Commission can
determine whether it is a user, owner or
operator of the Bulk-Power System that
is required to comply with mandatory
Reliability Standards.
470. Reliability Standard INT–005–1
does not include Levels of NonCompliance.
471. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard INT–005–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to INT–
005–1 that includes Levels of NonCompliance. Further, the Commission
requests that NERC provide additional
information regarding the role of the
interchange authority so that the
Commission can determine whether it is
a user, owner or operator of the BulkPower System that is required to comply
with mandatory Reliability Standards.
i. Response to Interchange Authority
(INT–006–1)

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i. NERC Proposal
472. INT–006–1, submitted with
NERC’s August 28, 2006 Supplemental
Filing to replace INT–002–0, ensures
that each arranged interchange is
checked for reliability before it is
implemented. It is applicable to
208 NERC’s glossary defines ‘‘interchange
authority’’ as ‘‘[t]he responsible entity that
authorizes implementation of valid and balanced
Interchange Schedules between Balancing
Authority Areas, and ensures communication of
Interchange information for reliability assessment
purposes.’’

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balancing authorities and transmission
service providers and requires these
entities to evaluate the energy profile
and the ramp rate of the generation to
support the transactions in response to
the request from the interchange
authority to change the status of an
interchange from an arranged
interchange to a confirmed interchange.
ii. Staff Preliminary Assessment
473. INT–006–1 is a new Reliability
Standard that mostly contains
Requirements from retired INT–002–0.
Staff noted in its Staff Preliminary
Assessment that INT–002–0 does not
explicitly apply to reliability
coordinators and transmission operators
for reliability assessments of
transactions before they are
implemented. Staff indicated that it is
important that the Reliability Standard
apply to these entities explicitly because
power flows for interchange
transactions cross multiple balancing
authority areas and affect multiple
transmission paths in an
Interconnection.
iii. Comments
474. As discussed below, INT–006–1
raises a number of issues that are
similarly raised by the Reliability
Standard it replaces, INT–002–0.
Therefore, relevant comments regarding
INT–002–0 are discussed here.
475. NERC maintains that staff’s
concerns regarding the applicability of
INT–002–0 to reliability coordinators
and transmission operators are
addressed by proposed Reliability
Standard INT–004–0, which addresses
reliability events such as potential or
actual SOL or IROL violations.
476. Similarly, Southern submits that
the Reliability Standard currently
applies to reliability coordinators and
transmission operators in their role in
the reliability assessment of individual
interchange transactions. Southern
explains that an individual Tag is first
assessed by the balancing authority
based on information on system limits
provided by the reliability coordinator
and/or the transmission operator. The
composite set of Tags and associated
schedules are then forwarded to the
reliability analysis services that
reliability coordinators and
transmission operators use for their
wide-area review. Southern contends
that it would not be appropriate for
reliability coordinators and
transmission owners to approve or deny
individual schedules during tagging,
and states that they should be involved
in reviewing tags in a composite
manner.

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iv. Commission Proposal
477. The Commission proposes to
approve INT–006–1 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
478. We agree with NERC and
Southern that it would be duplicative
for a reliability coordinator or
transmission owner to approve or deny
an individual schedule during tagging.
However, consistent with Southern’s
comment, we believe that reliability
coordinators and transmission operators
should review composite energy
interchange transaction information
(composite Tags) for wide-area
reliability impact. When the review
indicated a potential detrimental
reliability impact, the reliability
coordinator or transmission operator
should communicate to the sink
balancing authority the necessary
transaction modifications prior to
implementation. Accordingly, we
propose to require the ERO to modify
the proposed Reliability Standard to
ensure that reliability coordinators and
transmission operators validate
composite Tags (now called composite
arranged interchanges) for reliability.
479. The Commission notes that INT–
006–1 has included Measures and
Levels of Non-Compliance with
Requirements on balancing authorities
and transmission service providers to
check each arranged interchange for
reliability. We believe that INT–006–1
serves an important purpose in
assessing each interchange transaction
from a reliability perspective.
480. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard INT–006–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to INT–
006–1 that: (1) Makes it applicable to
reliability coordinators and
transmission operators; and (2) requires
reliability coordinators and
transmission operators to review
composite transactions from the widearea reliability viewpoint and, where
their review indicates a potential
detrimental reliability impact,
communicate to the sink balancing
authorities necessary transaction
modifications prior to implementation.

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j. Interchange Confirmation (INT–007–1)
i. NERC Proposal
481. INT–007–1, submitted with
NERC’s August 28, 2006 Supplemental
Filing, ensures that each arranged
interchange is checked for reliability
before it is implemented. INT–007–1
requires the interchange authority to
verify that the submitted arranged
interchanges are valid and complete
with relevant information and approvals
from the balancing authorities and
transmission service providers before
changing their status to confirmed
interchanges.
ii. Commission Proposal
482. We are concerned regarding the
applicability of INT–007–1 to the
interchange authority. As discussed
previously, it is not clear from NERC’s
definition whether an interchange
authority is a user, owner or operator of
the Bulk-Power System, or what types of
entities would be eligible to perform
such a function, and in our discussion
of INT–005–1 we request that NERC
provide additional information
regarding the role of the interchange
authority.
483. However, the Commission is
satisfied that the Requirements of the
Reliability Standard are appropriate to
ensure that interchange information is
verified prior to its implementation.
Accordingly, the Commission therefore
proposes to approve INT–007–1 as
mandatory and enforceable. We believe
that the proposed Reliability Standard is
just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.

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k. Interchange Authority Distributes
Status (INT–008–1)
i. NERC Proposal
484. INT–008–1, submitted with
NERC’s August 28, 2006 Supplemental
Filing, ensures that the implementation
of interchanges between source and sink
balancing authorities is coordinated by
an interchange authority. The Reliability
Standard applies to the interchange
authority. INT–008–1 requires the
interchange authority to distribute
information to all balancing authorities,
transmission service providers and
purchasing-selling entities involved in
the arranged interchange when the
status of the transaction has changed
from arranged interchange to confirmed
interchange.
ii. Commission Proposal
485. Again, we are concerned
regarding the applicability of INT–008–
1 to the interchange authority. As
explained above, the Commission

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requests additional information because
it is not clear from NERC’s definition
whether an interchange authority is a
user, owner or operator of the BulkPower System, or what types of entities
would be eligible to perform such a
function.
486. However, the Commission is
satisfied that the Requirements of the
Reliability Standard are appropriate to
ensure that interchange information is
coordinated between the source and
sink balancing authorities prior to its
implementation. Accordingly, the
Commission therefore proposes to
approve INT–008–1 as mandatory and
enforceable. We believe that the
proposed Reliability Standard is just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.
l. Implementation of Interchange (INT–
009–1)
i. NERC Proposal
487. INT–009–1, submitted with
NERC’s August 28, 2006 Supplemental
Filing, ensures that the implementation
of an interchange between source and
sink balancing authorities is
coordinated by an interchange
authority.
ii. Commission Proposal
488. The Commission is satisfied that
the proposed Reliability Standard
performs a necessary reliability function
by coordination of interchanges and
incorporating them into the ACE
calculation of the respective balancing
authorities. Further, INT–009–1
includes clear and appropriate
Requirements, Measurements and
Levels of Non-Compliance to ensure
proper implementation of interchange
transactions that have received
reliability assessments. The Commission
therefore proposes to approve INT–009–
1 as mandatory and enforceable. We
believe that the proposed Reliability
Standard is just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
m. Interchange Coordination
Exemptions (INT–010–1)
i. NERC Proposal
489. INT–010–1, submitted with
NERC’s August 28, 2006 Supplemental
Filing, allows certain types of
interchange schedules to be initiated or
modified by reliability entities under
abnormal operating conditions, and to
be exempt from compliance with other
Reliability Standards in the INT group.
The Reliability Standard is applicable to
the balancing authority and reliability
coordinator.

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490. The proposed Reliability
Standard, INT–010–1 has three
Requirements, which allows
modifications to interchange schedules
under abnormal system conditions: (1)
The balancing authority that
experiences a loss of resources covered
by an energy sharing agreement shall
ensure that a request for an arranged
interchange is submitted within
required time; (2) for a modification to
an existing interchange schedule that is
directed by a reliability coordinator for
a current or imminent reliability-related
reasons, the reliability coordinator
directs a balancing authority to submit
the modified arranged interchange
reflecting that modification within a
specified time; and (3) for a new
interchange schedule that is directed by
a reliability coordinator for current or
imminent reliability-related reasons, the
reliability coordinator directs a
balancing authority to submit an
arranged interchange reflecting that
interchange schedule within required
time.
ii. Staff Preliminary Assessment
491. INT–010–1 includes three
Requirements that replace Requirement
R1 from INT–004–0. Staff raised
concerns in the Staff Preliminary
Assessment on INT–004–0 with respect
to the use of transaction modifications
to address reliability events such as
actual IROL violations.
492. Specifically, staff noted that
INT–004–0 (now INT–010–1) allows
modification of an interchange
transaction to address an actual SOL or
IROL violation.209 Staff stated that, in
light of the procedures involved,
including submission, assessment and
approval, the total time necessary to
implement an interchange transaction
modification is expected to exceed
significantly the 30 minute time-frame
established in other Reliability
Standards, i.e., the requirement that the
system be returned from a SOL/IROL
violation to a secure operating state as
soon as possible, but no more than 30
minutes after the violation.210 INT–004–
0 (now INT–010–1) does not contain a
clear reference to this potential
209 NERC defines IROL as ‘‘[t]he 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.’’
NERC glossary at 8.
210 Reliability Standard IRO–005–0, Requirement
R3, states in part ‘‘[i]f a potential or actual IROL
violation cannot be avoided through proactive
intervention, the Reliability Coordinator shall
initiate control actions or emergency procedures to
relieve the violation without delay, and no longer
than 30 minutes.’’

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limitation, and staff observed that it
could lead to the inappropriate use of
transaction modification by reliability
entities to deal with actual SOL/IROL
violations. Staff expressed concern that
such actions could lead to the loss of
valuable time that would be needed to
readjust the system effectively using
other operational corrective actions.

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iii. Comments
493. There were no comments
submitted regarding the use of
transaction modification to address
actual IROL violations in INT–010–1.
iv. Commission Proposal
494. The Commission believes that it
is generally ineffective to use
transaction modifications to mitigate an
actual IROL violation or other system
condition that calls for expeditious
return to a secure system state.
Transaction modifications are even less
effective than the use of transmission
load relief (TLR) procedures to mitigate
an actual IROL violation. We note that
the Blackout Report specified that NERC
should ‘‘clarify that the [TLR] process
should not be used in situations
involving an actual violation of an
Operating Security Limit.’’ The Blackout
Report stated that ‘‘the TLR procedure is
often too slow for use in situations in
which an affected system is already in
violation of an Operating Security
Limit.’’ 211 We believe these same
concerns articulated in the Blackout
Report apply all the more so to a
transaction modification to address an
actual IROL violation.
495. Reliability Standard INT–010–1
includes provisions that allow
modification to an existing interchange
schedule or submission of a new
interchange schedule that is directed by
a reliability coordinator to address
current or imminent reliability-related
reasons. We interpret that these current
or imminent reliability-related reasons
do not include actual IROL violations as
they require immediate control actions
so that the system can be returned to a
secure operating state as soon as
possible and no longer than 30
minutes—a period that is much shorter
than the time that is expected to require
for new or modified transactions to be
implemented.
496. Accordingly, with the above
interpretation, the Commission
therefore proposes to approve INT–010–
1 as mandatory and enforceable. We
believe that the proposed Reliability
Standard is just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
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7. IRO: Interconnection Reliability
Operations and Coordination
a. Overview
497. The Interconnection Reliability
Operations and Coordination (IRO)
group of Reliability Standards detail the
responsibilities and authorities of a
reliability coordinator.212 The proposed
IRO Reliability Standards establish
requirements for data, tools and wide
area view, all of which are intended to
facilitate a reliability coordinator’s
ability to perform its responsibilities
and ensure the reliable operation of the
interconnected grid.
b. General Comments
498. CenterPoint believes that the IRO
series of Reliability Standards are
largely unnecessary as they are processoriented. It proposes the consolidation
of the IRO series of Reliability Standards
to replace the process based
Requirements with performance
metrics. If, after some time, these do not
achieve their reliability goal, they
should be rejected.
499. The Commission believes that
performance metrics will generally
complement and improve the proposed
Reliability Standards. However, we do
not believe that a Reliability Standard
based solely on performance metrics can
replace the proposed IRO Reliability
Standards. This is because performance
metrics, in general, are lagging
indicators, and therefore, could only
serve as reactive tools in improving the
Reliability Standards. Additionally, we
do not agree with CenterPoint’s
statement that the IRO series of
Reliability Standards are largely
unnecessary and can be replaced with
performance standards. On the contrary,
we believe that the proposed IRO series
of Reliability Standards establish
requirements for data, tools, and wide
area view and other real-time operating
activities that must be performed by a
reliability coordinator to ensure the
reliable operation of the interconnected
grid.
c. Reliability Coordination—
Responsibilities and Authorities (IRO–
001–0)
i. NERC Proposal
500. IRO–001–0 requires that a
reliability coordinator have reliability
212 According to the NERC glossary, at 13, a
reliability coordinator is ‘‘the entity with the
highest level of authority who is responsible for the
reliable operation of the Bulk Electric System, has
the Wide Area view of the Bulk Electric System,
and has the operating tools, processes and
procedures, including the authority to prevent or
mitigate emergency operating situations in both
next-day analysis and real-time operations * * *’’

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plans, coordination agreements and the
authority to act and direct reliability
entities to maintain reliable system
operations under normal, contingency
and emergency conditions. This
Reliability Standard would apply to
reliability coordinators and regional
reliability organizations.
ii. Staff Preliminary Assessment
501. The Staff Preliminary
Assessment noted that IRO–001–0 does
not explicitly assign responsibilities to
reliability coordinators in its Purpose or
Requirements. Responsibilities can only
be inferred from the definition of
reliability coordinator in the NERC
glossary.
iii. Comments
502. NERC comments that virtually
every Requirement in IRO–001–0
applies to reliability coordinators, so it
does not understand the Staff
Preliminary Assessment’s concern
regarding the assignment of a reliability
coordinator’s responsibilities. It also
states that the compliance registry will
include reliability coordinators.
503. MRO and ReliabilityFirst agree
with the Staff Preliminary Assessment.
MRO believes that a clarification of the
‘‘Purpose’’ section of IRO–001–0 is
warranted to better identify a reliability
coordinator’s responsibilities.
504. The ISO/RTO Council does not
share the Staff Preliminary Assessment’s
concern because each reliability
coordinator’s ‘‘reliability plan’’ is
approved by the NERC Operating
Committee. It states that this process is
intended to ensure that a reliability
coordinator’s peers validate that there is
an appropriate entity authorized to carry
out a reliability coordinator’s plans.
iv. Commission Proposal
505. The stated Purpose of IRO–001–
0 is ‘‘[r]eliability [c]oordinators must
have the authority, plans and
agreements in place to immediately
direct reliability entities within their
Reliability Coordinator Areas to redispatch generation, reconfigure
transmission, or reduce load to mitigate
critical conditions to return the system
to a reliable state.’’ As noted by NERC,
IRO–001–0 includes eight Requirements
that set forth reliability coordinator
responsibilities. However, these
Requirements do not comprehensively
match the responsibilities described in
the Purpose statement of this Reliability
Standard. Nonetheless, the Commission
observes that the IRO group of
Reliability Standards, taken as a whole,
together with the NERC glossary
definition of reliability coordinator,
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the role and responsibilities of a
reliability coordinator. Thus, while
IRO–001–0 could be improved by
comprehensively defining the overall
responsibility of a reliability
coordinator, as suggested in the title of
the Reliability Standard (Reliability
Coordination—Responsibilities and
Authorities), we will not propose to
direct NERC to do so.
506. Requirement R1 of IRO–001–0
provides that each regional reliability
organization, ‘‘subregion’’ or
‘‘interregional coordinating group’’ shall
establish one or more reliability
coordinators to continuously assess
transmission reliability and coordinate
emergency operations. Sections 502 and
503 of NERC’s Rules of Procedure
indicate that the ERO and Regional
Entities are responsible for registering,
certifying and verifying entities
pursuant to NERC’s compliance registry,
including reliability coordinators. The
Commission proposes that NERC
modify Requirement R1 to reflect the
process set forth in the NERC Rules of
Procedures, including the substitution
of Regional Entity for regional reliability
organization.
507. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard IRO–001–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to Requirement R1 of IRO–001–0 that:
(1) Reflects the process set forth in the
NERC Rules of Procedures; and (2)
eliminates the regional reliability
organization as an applicable entity.
d. Reliability Coordination—Facilities
(IRO–002–0)

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i. NERC Proposal
508. The proposed Reliability
Standard, IRO–002–0, establishes the
requirements for data, information,
monitoring and analytical tools and
communication facilities to enable a
reliability coordinator to meet the
reliability needs of the Interconnection,
act in addressing real-time emergency
conditions and control analysis tools.
NERC indicates that it plans to modify
IRO–002–0 to address the lack of
Measures and Levels of NonCompliance and resubmit it for
Commission approval in November
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ii. Staff Preliminary Assessment
509. The Staff Preliminary
Assessment did not identify any
substantive issues other than noting the
absence of Measures and Levels of NonCompliance.
iii. Comments
510. MISO contends that the proposed
Reliability Standard does not clearly
require all reliability coordinators to
demonstrate a functioning state
estimation, real-time contingency
analysis or a defined ‘‘wide area view’’
that includes visibility into neighboring
regions. According to MISO, the
requirement that a reliability
coordinator have ‘‘adequate analysis
tools’’ is a ‘‘loophole that belies the term
‘standard.’ ’’213 ReliabilityFirst asserts
that NERC should expedite the
development of missing compliance
elements within IRO–002–0.
iv. Commission Proposal
511. Requirement R7 currently does
not specifically require the reliability
coordinators to have specific tools
because it includes the phrase ‘‘such
as.’’ Requirement R7 should be modified
to explicitly require a minimum set of
tools that should be made available to
the reliability coordinator. We share
ReliabilityFirst’s concern that IRO–002–
0 lacks Measures and Levels of NonCompliance and direct NERC to add
these compliance elements in its
modification of the proposed Reliability
Standard. While the Commission has
identified concerns with regard to IRO–
002–0, we believe that the proposal
serves an important purpose in ensuring
that reliability coordinators have the
information, tools and capabilities to
perform their functions. NERC should
provide Measures and Levels of NonCompliance for this proposed Reliability
Standard. Nonetheless, the proposed
Requirements set forth in this Reliability
Standard are sufficiently clear and
objective to provide guidance for
compliance.
512. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard IRO–002–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
213 MISO Comments at 13, n.13, quoting IRO–
002–0, Requirement R7, which states, ‘‘[e]ach
Reliability Coordinator shall have adequate analysis
tools such as state estimation, pre- and postcontingency analysis capabilities (thermal, stability,
and voltage), and wide-area overview displays.’’

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of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit, a modification
to IRO–002–0 that: (1) Includes
Measures and Levels of NonCompliance and (2) modifies
Requirement R7 to explicitly require a
minimum set of tools for the reliability
coordinator.
e. Reliability Coordination—Wide Area
View (IRO–003–1)
i. NERC Proposal
513. The stated purpose of the
proposed Reliability Standard is that a
reliability coordinator must have a wide
area view of its own and adjacent areas
to maintain situational awareness. Wide
area view also facilitates a reliability
coordinator’s ability to calculate SOL
and IROL as well as determine potential
violations in its own area. NERC
indicates that it plans to modify IRO–
003–1 to address the absence of
Measures and Levels of NonCompliance and will resubmit it for
Commission approval in November
2006.
ii. Staff Preliminary Assessment
514. The Staff Preliminary
Assessment indicated that IRO–003–1
does not specify the criteria for defining
critical facilities in adjacent systems
whose status and loading could affect
the reliability of neighboring systems.
iii. Comments
515. NERC responds that IRO–003–1
provides that ‘‘critical facilities’’ are
those that, if they fail, would result in
an SOL or IROL violation. According to
NERC, this means that critical facilities
can only be determined by contingency
analysis and change through time, and
therefore, ‘‘may or may not exist.’’
Because an SOL or IRO violation is an
operating state that can only be
determined by running a series of ‘‘what
if’’ analyses, IRO–003–1 defines a
‘‘critical facility’’ as the facility that, if
it fails, places the transmission system
in a state ‘‘such that the failure of some
other element will result in facility
overloads, instability, or uncontrolled
cascading outages.’’ 214 NERC states that
the Commission should approve the
Reliability Standard and adds that it
will consider revising it to clarify the
definition of ‘‘critical facility.’’
516. MRO agrees with the Staff
Preliminary Assessment that this
Reliability Standard should be revised
to specify the criteria for defining
‘‘critical facilities’’ in adjacent systems.
MISO contends that the proposed
Reliability Standard does not clearly
214 NERC

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define the term ‘‘wide area view’’ that
includes visibility into neighboring
regions.
iv. Commission Proposal
517. The Blackout Report emphasized
that a principal cause of the August
2003 blackout was a lack of situational
awareness, which was in turn the result
of inadequate reliability tools and
backup capabilities.215 It pointed out
that the need for improved visualization
capabilities over a wide geographic area
has been a recurrent theme in blackout
investigations. The Blackout Report also
explained that the Task Force
investigation of the August 2003
blackout revealed that ‘‘there has been
no consistent means across the Eastern
Interconnection to provide an
understanding of the status of the power
grid outside of a control area,’’ and
improved visibility of grid status would
aid an operator in making adjustments
in operations to mitigate potential
problems.216 The Commission believes
that this issue is applicable to the entire
country and not just the Eastern
Interconnection. IRO–003–1 addresses
these important concerns of the
Blackout Report by requiring that a
reliability coordinator monitor its own
and adjacent areas to have a wide area
view that is ‘‘necessary to ensure that,
at any time, regardless of prior planned
or unplanned events, the Reliability
Coordinator is able to determine any
potential System Operating Limit and
Interconnection Reliability Operating
Limit violations within its Reliability
Coordination Area.’’ 217
518. The Commission notes that
Requirement R2 of the Reliability
Standard requires that each reliability
coordinator know the current status of
all ‘‘critical facilities’’ whose ‘‘failure,
degradation or disconnection’’ could
result in an SOL or IROL violation.
However, IRO–003–1 does not specify
the criteria for defining critical facilities.
NERC explains that specifying such
criteria is very difficult because critical
facilities can only be determined by
contingency analysis and change
through time. While NERC
acknowledges the absence of such
criteria, it requests that the Reliability
Standard be approved. In addition,
NERC indicates that it will consider a
modification to clarify the definition of
‘‘critical facility.’’
519. IRO–003–1 serves an important
reliability goal of requiring reliability
coordinators to have a wide area view
and maintain situational awareness. The
215 Blackout

Report at 159.

Commission proposes to direct NERC to
provide Measures and Compliance
elements for the proposed Reliability
Standard, and include criteria to define
‘‘critical facilities’’ in a reliability
coordinator’s area and its adjacent
systems. Nonetheless, the Requirements
set forth in IRO–003–1 are sufficiently
clear and objective to provide guidance
for compliance and a basis for
enforcement.
520. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard IRO–003–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to IRO–003–1 that includes: (1)
Measures and Levels of NonCompliance; and (2) criteria to define
the term ‘‘critical facilities’’ in a
reliability coordinator’s area and its
adjacent systems.
f. Reliability Coordination—Operations
Planning (IRO–004–1)
i. NERC Proposal
521. The stated purpose of IRO–004–
1 is to require that each reliability
coordinator conduct next-day
operations reliability analyses to ensure
that the system can be operated reliably
in anticipated normal and contingency
system conditions. Operations plans
must be developed to return the system
to a secure operating state after
contingencies and shared with other
operating entities.
ii. Staff Preliminary Assessment
522. The Staff Preliminary
Assessment noted that, while IRO–004–
1 requires Reliability Coordinators to
conduct next-day reliability analyses to
ensure reliable operations in anticipated
normal and contingency event
conditions, it ‘‘does not require that the
system be assessed in the next-day
planning analysis to identify the control
actions needed to bring the system back
to a stable state, with an effective
implementation time of within 30
minutes, so that the system will be able
to withstand the next contingency
without cascading.’’ 218
iii. Comments
523. NERC asserts that Requirement
R1 of IRO–004–1 does require next-day

216 Id.
217 IRO–003–1,

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operations planning studies and does
not require modification.219 Similarly,
ISO–RTO Council comments that the
proposed Reliability Standard contains
the appropriate requirements for
ensuring reliable operations because
there are other tools available to meet
the needs identified with a next-day
analysis. These alternative tools are
adequate for conducting next-day
analysis.
524. MRO suggests that the next-day
reliability analyses do not need to
include the control actions that would
be implemented to bring the system
back to a stable state. MRO argues that,
in most cases, the actual dispatch and
condition of the system during real-time
is not representative of the dispatch
used in the model for performing the
next-day analyses and, thus, mitigation
action needed during real-time will
differ.
525. ReliabilityFirst agrees in general
with the Staff Preliminary Assessment’s
comments, but cautions that the
proposal to identify and study all
possibilities for alleviating SOL and
IROL may be impractical and
unachievable.
iv. Commission Proposal
526. The Commission agrees with
NERC that the proposed Reliability
Standard requires next day operations
planning. While the Staff Preliminary
Assessment mentions the next-day
planning analysis and the need to study
events that would result in cascading for
the first contingency, this was not the
intended focus of staff’s observations.
Rather, the thrust of staff’s concern was
that the control actions necessary to
return the system to a stable state after
the first contingency must do so
effectively within the specified
implementation time of less than 30
minutes.220 To assure that an operator
has either sufficient generation
resources, transmission modifications,
or load shedding capability to avoid a
cascading outage after the first
contingency, the control actions should
be identified in the next-day analyses to
better prepare system operators to deal
219 Requirement R1 requires that ‘‘Each Reliability
Coordinator shall conduct next-day reliability
analyses for its reliability coordinator area to ensure
that the Bulk Electric System can be operated
reliably in anticipated normal and contingency
event conditions. The reliability coordinator shall
conduct contingency analysis studies to identify
potential interface and other SOL and IROL
violations, including overloaded transmission lines
and transformers, voltage and stability limits, etc.’’
220 IRO–005–1, Requirement R3 states, in relevant
part, ‘‘* * * the [r]eliability [c]oordinator shall
initiate control actions or emergency procedures to
relieve the violations without delay, and no longer
than 30 minutes.’’

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with system contingencies or
emergencies in real-time operations.
527. The Commission believes that
identification of potential control
actions will aid system operators in
performance of their duties. While MRO
is correct that control actions identified
in a next-day analysis may not always
be useful in a real-time scenario,
nonetheless, the control actions
identified in the next-day analysis may
quite often be relevant and having the
system operators aware of options
earlier on would be helpful.
528. The Commission agrees with
NERC regarding the applicability of this
Reliability Standard. While most
Requirements pertain to reliability
coordinators, they also require each
balancing authority, transmission
operator, transmission owner, generator
operator, and load-serving entity to
provide information to its reliability
coordinator for system studies. It also
requires that each transmission
operator, balancing authority and
transmission service provider to comply
with the directive of its reliability
coordinator based on next-day
assessments.
529. While the Commission has
identified one concern with regard to
IRO–004–1, the proposed Reliability
Standard serves an important purpose
by requiring that each reliability
coordinator conduct next-day
operations reliability analyses to ensure
that the system can be operated reliably
in anticipated normal and contingency
system conditions. Further, the
Requirements set forth in IRO–004–1 are
sufficiently clear and objective to
provide guidance for compliance and a
basis for enforcement.
530. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard IRO–004–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to IRO–004–1 that requires the next-day
analysis to identify effective control
actions that can be implemented within
30 minutes during contingency
conditions.
g. Reliability Coordination—Current
Day Operations (IRO–005–1)
531. IRO–005–1 ensures energy
balance and transmission reliability for
the current day by identifying tasks that

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reliability coordinators must perform
throughout the day. The stated
purposed of the proposed Reliability
Standard is that a reliability coordinator
must be continuously aware of
conditions within its area and include
this information in its reliability
assessments. Additionally, a reliability
coordinator must monitor the
parameters of the system that may have
a significant impact upon its area and
neighboring reliability coordinator
areas. NERC indicates that it plans to
modify IRO–005–0 to address the lack of
Measures and Levels of NonCompliance and resubmit it for
Commission approval in November
2006.
i. Staff Preliminary Assessment
532. Requirement R3 of IRO–005–1
provides that: ‘‘[i]f a potential or actual
IROL violation cannot be avoided
through proactive intervention, the
Reliability Coordinator shall initiate
control actions or emergency procedures
to relieve the violation without delay,
and no longer than 30 minutes. The
Reliability Coordinator shall ensure all
resources, including load shedding, are
available to address a potential or actual
IROL violation.’’ The Staff Preliminary
Assessment pointed out that this
Requirement may be interpreted in
either of two ways: (1) a less
conservative interpretation in which an
IROL is allowed to be exceeded during
normal operations, i.e., prior to a
contingency, provided that corrective
actions are taken within 30 minutes;
and (2) a more conservative
interpretation that an IROL should only
be exceeded after a contingency and the
system must subsequently be returned
to a secure condition as soon as
possible, but no longer than 30 minutes.
Therefore, IRO–005–1 creates the
situation in which the system may be
one contingency away from potential
cascading failure if operated under the
less conservative interpretation or two
contingencies away from potential
cascading failure if the more
conservative interpretation is adopted.
ii. Comments
533. NERC acknowledges that the
SOLs and IROLs are among the most
important operating measures contained
in the proposed Reliability Standards
and that it continues to refine the
definitions of both these terms. NERC
explains that SOL and IROL violations
do not necessarily result from an event
or ‘‘contingency.’’ It asserts that the
transmission system may ‘‘drift’’ into an
SOL or IROL violation without any
triggering event and with every element
of the transmission system operation

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within its own safe limit.221 NERC states
that the point of these limits is not
whether a particular transmission
facility is operating within its normal
limits, but to determine what happens if
the transmission element fails regardless
of how much power is flowing through
it.
534. NERC states that it will consider
clarifying those Reliability Standards
that indicate a contingency is not
required and, as a corollary, that a
Reliability Standard should not allow a
system operator to ‘‘drift’’ in and out of
an SOL or IROL violation. Further,
NERC will continue to refine its
definition of SOL and IROL violations.
The Operating Committee has
commissioned an Operating Limits
Definition Task Force to work on this
matter, and the Task Force will bring its
final suggestions to the Operating
Committee by the end of 2006. NERC
indicates that it will review proposed
Reliability Standards IRO–003–0 and
IRO–005–1 and address SOL and IROL
violation mitigation.
535. According to NERC, the 30minute limit for mitigating IROL
violations is one of many reliability
standards gleaned from decades of
interconnected systems operation
experience, and represents a tradeoff
between: (1) sufficient time to allow the
transmission operator or reliability
coordinator to mitigate the violation
without having to shed load or
disconnect transmission system
components; and (2) the risk that some
event will occur before the mitigating
action is taken. NERC explains that
action is required ‘‘as soon as possible’’
or ‘‘without delay,’’ however, exceeding
an SOL or IROL for no more than 30
minutes is not a violation. It contends
that this approach is reasonable because
it allows the system operator to decide
on what course of action to take.
Operating options that are less severe
than shedding load are often available,
but it explains that these actions may
require more time for implementation.
NERC asserts that its committees and
subcommittees have debated the phrase,
‘‘as soon as possible’’ for years and have
not found a better way to articulate a
requirement that allows the system
operator the leeway to decide the best
course of action.
536. MRO and NYSRC agree with the
Staff Preliminary Assessment that IRO–
005–1 allows varying interpretations
with respect to IROL limits under
normal and contingency conditions and
should be revised to clarify how IROL
events are addressed. ReliabilityFirst
believes that a methodology to address
221 See

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SOLs and IROLs must be developed. It
argues that this will aid in clarifying
that exceeding limits is not acceptable
operating practice. According to
ReliabilityFirst, proposed Reliability
Standards are being developed that will
provide more definition and detail in
this area. It urges the acceleration of this
development.
537. MidAmerican believes that staff’s
‘‘more conservative’’ interpretation may
be overly conservative and should not
be adopted. It contends that, in an
interconnected transmission network, it
is difficult to operate prior to a
contingency so that potential IROL
violations are avoided at all times. It
believes that to adopt the more
conservative interpretation could
require an operator to scale back the
operation of its system pre-contingency
by an inordinate amount to provide a
safety margin so as not to risk a
potential IROL violation even for only
very short periods of time.
MidAmerican maintains that such an
operation would result in slightly more
reliable operation at an unjustifiably
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iii. Commission Proposal
538. The Commission proposes to
approve IRO–005–1 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard and perform
a survey of present operating practices
and actual operating experience
concerning drifting in and out of IROL
violations.
539. The Commission believes that
one of the fundamental principles in
operating the Bulk-Power System
reliably is that the system must be
capable of supplying firm demand and
supporting firm transactions while
retaining the capability to withstand a
critical contingency without resulting in
instability, uncontrolled separation or
cascading failures. This is affirmed by
the term, Reliable Operation, as set forth
in section 215(a)(4) of the FPA 222 and
the technical requirement as stated in
Table 1 of Reliability Standard TPL–
002–0.223 Therefore, in order to achieve
222 Reliable operation: Operating the elements of
the Bulk-Power System within equipment and
electric system thermal, voltage and stability limits
so that instability, uncontrolled separation, or
cascading failures of such system will not occur as
a result of sudden disturbance, including a
Cybersecurity Incident, or unanticipated failure of
system elements.
223 TPL–002–0 System Performance Following
Loss of a Single Bulk Electric System Element,
Table 1: For Category B events resulting in loss of
a single element, the system remains stable and
both thermal and voltage limits are within
applicable ratings with no loss of demand or
curtailment of firm transfers and no cascading
outages.

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the reliability goal stated in the
definition of Reliable Operation, the
Bulk-Power System must be operated to
respect all applicable IROLs during
normal conditions, i.e. prior to a
contingency, so that the system is
capable of withstanding a critical
contingency without resulting in
instability, uncontrolled separation or
cascading outages.
540. IRO–005–1 allows a system
operation to respect IROLs in two
possible ways: (1) allowing IROL to be
exceeded during normal operations, i.e.,
prior to a contingency, provided that
corrective actions are taken within 30
minutes or (2) exceeding IROL only after
a contingency and subsequently
returning the system to a secure
condition as soon as possible, but no
longer than 30 minutes. Thus, the
system can be one contingency away
from potential cascading failure if
operated under the first interpretation
and two contingencies away from
cascading failure under the second
interpretation.
541. The Commission notes that the
proposed Reliability Standards (e.g.
TOP–007–0) do not consider operation
exceeding IROL for less than 30 minutes
as a compliance violation. This, in
addition to the less conservative
interpretation that IROL violation is
permissible during normal operations,
opens up a significant reliability gap
that allows operations with IROL
violations for less than 30 minutes at a
time. Under the mandatory reliability
construct, there would be no
enforcement provision to sanction
against such actions even they resulted
in cascading outages.
542. The Commission believes a
proactive standard, that clearly defines
that reliable operations means operating
the system within IROLs and requires
such operating practice be reinforced by
periodic reporting of the frequency,
duration and causes of IROL violations,
is needed to prevent or mitigate the risk
of blackouts. This is because, by
definition, when the system is operating
in violation of IROLs and if a critical
contingency occurs, cascading outages
will result.
543. Operating the system during
normal system conditions with IROL
violations is also known in the industry
as ‘‘drifting in and out’’ of an IROL
violation. This is the first and less
conservative interpretation of the
proposed Reliability Standard as stated
above and one contingency away from
cascading failure. We particularly note
that the NERC Operating Committee
recommended that the proposed
Reliability Standards should not allow a

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64823

system operator to ‘‘drift’’ in and out of
an SOL or IROL violation.
544. The Commission agrees with
ReliabilityFirst’s comments that
exceeding any limit is not acceptable
operating practice. The system should
strive to operate in a secure state that
respects all IROLs under normal
conditions at all times, except for
infrequent and unanticipated changing
conditions that are beyond the control
of reliability coordinators and operating
entities under their jurisdiction.
Furthermore, these unanticipated
factors should be limited and should not
include load pick-up and drop-off as
changes in load demand or coordinated
generation dispatches and transactions,
all of which would have obtained prior
assessments and approvals.
545. In contrast to MidAmerican’s
comments, the Commission does not
believe that respecting IROL under
normal system conditions requires an
inordinate amount of operating margin
which may result in an unjustifiably
high price. However, we propose to
direct NERC to perform a survey of
present operating practices and actual
operating experience concerning
drifting in and out of IROL violations.
As part of the survey, we will require all
reliability coordinators to report any
violations of IROLs, their causes, the
date and time of the violation, and the
duration in which actual operations
exceeded IROL to the ERO on a monthly
basis for one year beginning two months
after the effective date of the final rule.
546. The Commission also finds that
well-designed Levels of NonCompliance should duly recognize the
magnitude, frequency and duration of
IROL violations under normal system
conditions and differentiate those
caused by system contingencies. The
former, if not severe, frequent, of
extended duration or willfully
deployed, should not incur heavy
penalties. Nevertheless, these
occurrences and causes should be
recorded and reported. We understand
that most reliability coordinators and
transmission operators already keep
records of power flows on transmission
interfaces, transmission paths or
flowgates versus their respective IROLs
as a part of their operating and
management tools. We believe that the
practice of separately recording and
reporting IROL violations and durations
occurring under normal and
contingency system conditions serves
several purposes, including: (1)
Reinforcing the sound principles of
reliable system operations; (2) serving as
a performance metric to gauge the
effectiveness of Reliability Standards,
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and the health of the Bulk-Power
System; and (3) proactively improving
system reliability over time.
547. It is important to keep in mind
that, while the Commission has
concerns regarding Requirement R3, the
proposed Reliability Standard contains
17 Requirements relating to current day
operations. With this perspective, while
the Commission has identified a number
of concerns with regard to IRO–005–1,
we believe that the proposed Reliability
Standard adequately addresses the
important reliability goal of requiring a
reliability coordinator to be
continuously aware of conditions
within its reliability coordinator area
and include this information in its
reliability assessments. Further, NERC
should provide Measures and Levels of
Non-Compliance elements for this
proposed Reliability Standard.
Nonetheless, the proposed
Requirements set forth in this Reliability
Standard are sufficiently clear and
objective to provide guidance for
compliance.
548. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard IRO–005–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to IRO–005–1 that includes Measures
and Levels of Non-Compliance. We
propose that the Measures and Levels of
Non-Compliance specific to IROL
violations should be commensurate
with the magnitude, duration, frequency
and causes of the violation. Further, as
discussed above, we propose that the
ERO conduct a survey on IROL practices
and experiences. The Commission may
propose further modifications to IRO–
005–1 based on the survey results.
h. Reliability Coordination—
Transmission Loading Relief (IRO–006–
3)

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i. NERC Proposal
549. IRO–006–3 ensures that a
reliability coordinator has a coordinated
method to alleviate loadings on the
transmission system if it becomes
congested to avoid limit violations.
IRO–006–3 establishes a detailed
Transmission Loading Relief (TLR)
process for use in the Eastern
Interconnection to alleviate loadings on
the system by curtailing or changing

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transactions based on their priorities
and according to different levels of TLR
procedures.224 The proposed Reliability
Standard includes a regional difference
for reporting market flow information to
the Interchange Distribution Calculator
rather than tagged transaction
information for the MISO and PJM
areas.225 It also references the
equivalent Interconnection-wide
congestion management methods used
in the WECC and ERCOT regions.
550. On August 28, NERC submitted
IRO–006–3 for approval, which replaces
IRO–006–1. The new proposal would
extend the PJM/MISO regional
difference to SPP and contains some
additional changes to the Attachment to
the Reliability Standard. The comments
submitted in response to the
Preliminary Staff Assessment on IRO–
006–1 apply equally to IRO–006–3.226
ii. Staff Preliminary Assessment
551. The Staff Preliminary
Assessment noted that IRO–006–1 does
not address concerns expressed in the
Blackout Report that call for
‘‘clarify[ing] that the transmission
loading relief (TLR) process should not
be used in situations involving an actual
violation of an Operating Security Limit
[SOL].’’ 227 It also noted that
Requirement R2, which provides that a
reliability coordinator experiencing a
potential or actual SOL or IROL
violation shall select from either a local
or Interconnection-wide transmission
loading relief procedure, could lead a
reliability system operator to
‘‘inappropriately use transmission
loading relief procedures to mitigate
actual IROL violations’’ and, ‘‘in doing
so, valuable time that could be utilized
to re-adjust the system by other, more
effective, operating measures would be
lost.’’ 228
iii. Comments
552. NERC explains that the TLR
procedure is a method of addressing the
224 The equivalent Interconnection-wide
transmission loading relief procedures for use in
WECC and ERCOT are known as ‘‘WSCC
Unscheduled Flow Mitigation Plan’’ and Section 7
of the ‘‘ERCOT Protocols,’’ respectively.
225 The NERC glossary defines Interchange
Distribution Calculator as ‘‘The mechanism used by
reliability coordinators in the Eastern
Interconnection to calculate the distribution of
Interchange Transactions over specific Flowgates. It
includes a database of all Interchange Transactions
and a matrix of the Distribution Factors for the
Eastern Interconnection.’’ NERC glossary at 6.
226 We note that on September 29, 2006, NERC
submitted Version 2 of the same Reliability
Standard (ERO–006–2) in Docket No. ER06–1545–
000, seeking approval of its TLR procedure
pursuant to section 205 of the FPA.
227 Blackout Report, Recommendation No. 31 at
163.
228 Staff Preliminary Assessment at 69.

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impacts of bilateral transactions causing
parallel flows. The procedure curtails
bilateral transactions, which causes
generation to be re-dispatched, which in
turn changes the flow patterns on the
transmission system. The curtailments
are based on a power flow model of the
Eastern Interconnection, and have the
effect of reducing the loading on those
lines over which the transactions are
actually flowing.
553. NERC agrees that the TLR
procedure alone is usually not effective
as a control measure to mitigate an IROL
violation and explains that the TLR
procedure was not intended to be
effective in this manner.229 It states that,
while TLR procedures can be effective
as a preventive tool to adjust and
manage bilateral transactions so that
limit violations do not occur, other
options such as local or market area redispatch and transmission
reconfiguration are more precise for a
system operator to stay within SOLs and
IROLs.
554. NERC believes that transmission
operators and reliability coordinators
understand that the TLR procedure is
not the only method for mitigating an
SOL or IROL violation and that the
proposed Reliability Standard—as one
tool among many—is adequate and
necessary to protect Bulk-Power System
reliability. NERC states that ‘‘it does not
believe the recommendation of the
Blackout Report that ‘‘the [TLR] process
should not be used in situations
involving an actual violation of an
Operating Security Limit [SOL]’’ needs
further discussion to determine possible
changes to standard.’’ 230
555. ISO/RTO Council states that,
although TLR should not be considered
an emergency procedure,231
Requirement R1 of IRO–006–3 does not
require use of TLR procedures and
permits the implementation of existing
policies and procedures to correct
transmission loading.232 It further states
that Requirement R1 appropriately
identifies a reliability coordinator as
being responsible for actions related to
transmission loading. As a result,
229 NERC

Comments at 49.
at 50.
231 In its comments on EOP–002–0 regarding
Capacity and Energy Emergencies, ISO/RTO
Council elaborates that it ‘‘agrees with FERC Staff’s
concerns that TLRs are not appropriate for
addressing actual transmission emergencies,
because TLRs are not a method that can be used
quickly or predictably enough in situations where
an operating security limit is close to, or actually
being violated.’’
232 IRO–006–1, Requirement R1 states, ‘‘[a]
[r]eliability [c]oordinator shall take appropriate
actions in accordance with established policies,
procedures, authority, and expectations to relieve
transmission loading.’’
230 Id.

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because Requirement R1 clearly does
not specify the use of TLR, and instead
explicitly calls for the use of appropriate
tools available to the reliability
coordinator, the ISO/RTO Council
believes that IRO–006–3 allows entities
sufficient flexibility to ensure reliability.
556. However, ISO/RTO Council
explains the limitations of TLR in EOP–
002–0 that most ISOs and RTOs use redispatch to correct SOL and IROL
violations instead of TLR procedures
because re-dispatch is superior to TLR
procedures for the purposes of ensuring
system reliability. It further states that
as a result, the applicability to an ISO
or RTO region of any Reliability
Standard that provides for the use of
TLR procedures is not clear, and if
applied, could actually be detrimental
to reliability.
557. ReliabilityFirst agrees in general
with the Staff Preliminary Assessment.
NYSRC comments that the concerns
articulated by staff are not significant
enough to prevent approval of the
proposed Reliability Standard. MRO
believes that IRO–006–3 should be
modified to clarify the use of TLR as
proposed by the Staff Preliminary
Assessment due to the identified
interpretation issue.
558. CenterPoint contends that the
ERCOT region should be explicitly
exempted from these [IRO] Reliability
Standards since ERCOT does not use
TLR procedures. Instead, it manages
congestion using procedures relevant to
ERCOT market rules.
iv. Commission Proposal
559. The Commission proposes to
approve IRO–006–3 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard as discussed
below.
560. The Commission notes that
NERC agrees that the TLR procedure is
usually not effective by itself as a
control measure to mitigate an IROL
violation, the procedure is not intended
to be effective in this manner and that
it be combined with other effective
methods such as reconfiguration, redispatch or load shedding until relief
requested by the TLR process is
achieved.233 The Commission is
concerned, however, that the
Requirements in IRO–006–3 do not
sufficiently convey the availability of
alternatives, nor highlight the
inefficiency of TLR procedure which
requires a lead time for implementation
much longer than the allowable 30
minutes to return the system from IROL
violation to a secure state. This could

potentially mislead a transmission
operator or reliability coordinator that is
attempting to mitigate an IROL violation
to first deploy the TLR procedure only
to find out later that other more effective
operating measures should have been
used. In addition, we duly note ISO/
RTO Council’s comment that the
applicability to an ISO or RTO region of
any Reliability Standard that provides
for the use of TLR procedures is not
clear, and if applied, could actually be
detrimental to reliability. Since the
system is subject to cascading outages
when it is in IROL violation, we have
particular concern regarding the use of
TLR to mitigate IROL violations and less
so on its use on SOLs since the latter
would not result in cascading outages.
561. While NERC suggests that
transmission operators and reliability
coordinators understand that the TLR
procedure is not the sole method for
mitigating an SOL or IROL violation, the
Commission notes that the Blackout
Report suggests otherwise with regard to
the causes of the August 2003 cascading
blackout since the operator was first
attempting to use TLR to mitigate an
IROL violation only to find out it was
ineffective.234 This led the Blackout
Task Force to recommend that NERC
‘‘clarify that the [TLR] process should
not be used in situations involving an
actual violation of an Operating Security
Limit.’’ 235
562. We propose that the Reliability
Standard should also clearly provide the
flexibility for ISOs and RTOs to rely on
re-dispatch, as suggested by ISO/RTO
Council. Accordingly, we propose to
direct that NERC modify IRO–006–3 to
(1) include a clear warning that TLR
procedure is an inappropriate and
ineffective tool to mitigate IROL
violation and (2) to identify effective
alternatives to use of the TLR procedure
in situations involving an IROL
violation.
563. With regard to CenterPoint
suggestion that the ERCOT region be
explicitly exempted from compliance
with IRO–006–3, we note that our
regulations require that any such
proposal must be developed through an
open, stakeholder process and
submitted to the Commission by the
ERO.
564. The Commission notes that
Requirement R2.2 identifies the ‘‘WSCC
Unscheduled Flow Mitigation Plan’’ 236
as an equivalent load relief procedure
for use in the Western Interconnection.
The referenced document contains
governance, compensation, charges for
234 See

Blackout Report at 63.
at 163.
236 WSCC is an old reference to WECC.
235 Id.

233 NERC

Comments at 49.

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use of the procedure and limitations on
applicable facilities which are unusual
in a Reliability Standard. The
Commission believes that these issues
are part of the transition to mandatory
Reliability Standards and are mainly
administrative in nature. The
Commission believes that the WECC
approach is superior to the national
standard because it uses phase angle
regulators, series capacitors and back-toback DC lines to mitigate contingencies
without curtailing transactions. The
Commission proposes to approve its
use.
565. The Commission notes that
Requirement R2.3 identifies section 7 of
the ERCOT Protocols as an equivalent
load relief procedure for use in the
Texas Interconnection. The Protocol
contains significant details about the
ERCOT market that are unusual in a
Reliability Standard. The Commission
believes that these issues are part of the
transition to mandatory Reliability
Standards and are mainly
administrative in nature. The
Commission believes that the ERCOT
zonal LMP approach is superior to the
national standard in that it uses
generation re-dispatch and pricing to
mitigate congestion without curtailing
transactions. The Commission proposes
to approve its use.
566. While the Commission has
identified concerns with regard to IRO–
006–3, we believe that the proposal
serves an important purpose in ensuring
reliability coordinators have a
coordinated method for alleviating
loadings on the transmission system
when it becomes too congested to avoid
potential SOL and IROL violations. It
also includes a regional difference for
reporting market flow information to the
Interchange Distribution Calculator. The
Commission believes that it is important
for NERC to clarify that the TLR process
is not the only, and perhaps not even
the preferred, method to mitigate an
SOL and especially IROL violation. The
proposed Requirements set forth in
IRO–006–3 are sufficiently clear and
objective to provide guidance for
compliance.
567. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard IRO–006–
3 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification

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to IRO–006–3 that: (1) Includes a clear
warning that TLR procedure is an
inappropriate and ineffective tool to
mitigate IROL violations; (2) identifies
in a Requirement the available
alternatives to use of the TLR procedure
to mitigate an IROL violation; and (3)
includes Measures and Levels of NonCompliance that address each
Requirement.
i. Regional Difference to IRO–006–3:
PJM/MISO/SPP Enhanced Congestion
Management (Curtailment/Reload/
Reallocation)
i. NERC Proposal
568. IRO–006–003 provides for a
regional difference for MISO, PJM and
SPP. NERC explains that this regional
difference is needed to allow RTO
market practices, simplify transaction
information requirements for market
participants, and provide reliability
coordinators with appropriate
information for security analysis and
curtailments, reloads, reallocations and
redispatch requirements.
ii. Staff Preliminary Assessment
569. This regional difference was not
addressed in the Staff Preliminary
Assessment.

sroberts on PROD1PC70 with PROPOSALS

iii. Comments
570. MISO and PJM, in a joint filing,
contend that there is unduly
discriminatory treatment of the market
flows of MISO and PJM versus the
generation-to-load impacts of nonmarket entities in the application of the
TLR standard. They argue that NERC
should modify IRO–006–3 and the
MISO/PJM regional difference to
require: (1) Netting of generation-to-load
impacts; (2) reporting to the Interchange
Distribution Calculator all net
generation-to-load impacts for both
market and non-market transmission
providers; and (3) modifying the
curtailment threshold to a standard
percentage for all impacts thus reported
to the Interchange Distribution
Calculator to a level that is technically
feasible to implement and on a nondiscriminatory basis. MISO and PJM
also note that they, as well as SPP, have
been working through various groups to
achieve a consensus on these changes.
According to MISO and PJM, these
efforts were fruitful, but they were
unable to complete the changes prior to
NERC’s April 6, 2006 submission of its
Version 0 reliability standards for
Commission approval. The Commission
believes that SPP could experience the
same problems identified by MISO and
PJM.

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iv. Commission Proposal
571. The Commission believes that
the comments and information
presented by MISO and PJM are
persuasive. However, before acting on
this regional difference, the Commission
invites comments to assure that we have
a full and complete record on which to
base our decision.
572. The Commission notes that
MISO and PJM indicate that their
competition concerns are being
addressed in discussions with NERC
and other relevant entities. The
Commission prefers that PJM, MISO and
others continue to pursue a negotiated
resolution rather than having the
Commission impose a solution on
market participants. Accordingly, the
Commission will not propose to
approve or remand this regional
difference.
j. Procedures, Processes, or Plans to
Support Coordination Between
Reliability Coordinators (IRO–014–1)
i. NERC Proposal
573. The stated purpose of IRO–014–
1 is to ensure that each reliability
coordinator’s operations are coordinated
such that they will not have an adverse
reliability impact on other reliability
coordinator areas and to preserve the
reliability benefits of interconnected
operation. Specifically, IRO–014–1
ensures energy balance and
transmission by requiring a reliability
coordinator to have operating
procedures, processes or plans for the
(1) exchange of operating information
and (2) coordination of operating plans.
ii. Staff Preliminary Assessment
574. No substantive issues were
identified for IRO–014–1.
iii. Comments
575. No comments were submitted
regarding IRO–014–1.
iv. Commission Proposal
576. The Commission believes that
IRO–014–1 contains sufficient details in
the specification of the required
procedures, processes or plans for a
reliability coordinator to support
coordination among it neighbors, and
agreements that all reliability
coordinators, as the only applicable
entity, must take the indicated actions
to ensure coordinated and reliable
operations.
577. For the reasons discussed above,
the Commission proposes to approve
Reliability Standard IRO–014–1 as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.

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k. Notifications and Information
Exchange Between Reliability
Coordinators (IRO–015–1)
i. NERC Proposal
578. Proposed Reliability Standard
IRO–015–1 establishes Requirements for
a reliability coordinator to share and
exchange reliability-related information
among its neighbors and participate in
agreed-upon conference calls and other
communication forums with adjacent
reliability coordinators. This exchange
of reliability-related information among
reliability coordinators facilitates
situation awareness.
ii. Staff Preliminary Assessment
579. No substantive issues were
identified for IRO–015–1.
iii. Comments
580. No comments were submitted
regarding IRO–015–1.
iv. Commission Proposal
581. The Commission believes that
IRO–015–1 contains sufficient
Requirements to ensure that reliability
coordinators inform and exchange
information with other reliability
coordinators, as the only applicable
entity, to ensure coordinated operations.
582. For the reasons discussed above,
the Commission proposes to approve
Reliability Standard IRO–015–1 as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.
l. Coordination of Real-Time Activities
Between Reliability Coordinators (IRO–
016–1)
i. NERC Proposal
583. IRO–016–1 establishes
Requirements for coordinated real-time
operations, including: (1) Notification of
problems to neighboring reliability
coordinators and (2) discussions and
decisions for agreed-upon solutions for
implementation. It also requires a
reliability coordinator to maintain
records of its actions. Where a
disagreement arises, IRO–016–1 requires
that reliability coordinators work with
one another until a system problem is
resolved or implement the more
conservative solution.
ii. Staff Preliminary Assessment
584. No substantive issues were
identified for IRO–016–1.
iii. Comments
585. No comments were submitted
regarding IRO–016–1.
iv. Commission Proposal
586. The Commission believes that
IRO–016–1 contains sufficient

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requirements for a reliability
coordinator to inform, discuss and
identify a solution with other reliability
coordinators to prevent or resolve a
problem that requires joint actions from
all affected reliability coordinators as
the only applicable entity. It also clearly
articulates binding and conservative
corrective actions to be taken in the
event that an agreement cannot be
reached among them.
587. For the reasons discussed above,
the Commission proposes to approve
Reliability Standard IRO–016–1 as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.
8. MOD: Modeling, Data, and Analysis

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a. Overview
588. The Modeling, Data, and
Analysis group of Reliability Standards
are intended to standardize
methodologies and system data needed
for traditional transmission system
operation and expansion planning,
reliability assessment, and the
calculation of available transmission
capacity (ATC) in an open access
environment. The 23 standards may be
grouped into four distinct categories.
The first category covers methodology
and associated documentation, review,
and validation of Total Transfer
Capability (TTC), ATC, Capacity Benefit
Margin (CBM), and Transmission
Reliability Margin (TRM)
calculations.237 The second category
covers steady-state and dynamics data
and models.238 The third category
covers actual and forecast demand
data.239 The fourth category covers the
verification of generator real and
reactive power capability.240
OATT Reform NOPR and the MOD
Standards
589. The Commission has been
considering ATC, TTC, CBM and TRM
calculation issues in Docket Nos.
RM05–17–000 and RM05–25–000, and
is addressing them in the OATT Reform
NOPR.241 Among other things, the
OATT Reform NOPR discusses the need
for consistency and transparency of
ATC, TTC, CBM, and TRM. It proposes
that public utilities, working through
NERC/NAESB, would use the guidelines
in the OATT Reform NOPR to revise the
relevant standards and business
practices, and asks for comments on
certain proposals. It also recognizes that
there are still many unspecified
237 MOD–001–0

through MOD–009–0.
through MOD–015–0.
239 MOD–016–0 through MOD–021–0.
240 MOD–024–1 through MOD–025–1.
241 OATT Reform NOPR, 71 FR 32636 at 32658.
238 MOD–010–0

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elements in the calculation processes
and development of modeling
assumptions, and deficiencies in data
exchange that may have a negative
impact on both transmission system
reliability and competition.242
590. The industry also acknowledged
this problem and has taken steps to
address the lack of consistency and
transparency in the way ATC is
calculated. NERC formed a Long-Term
Available Flowgate Capacity 243 (AFC)/
ATC Task Force to review NERC’s
standards on ATC, which issued a final
report in 2005.244 Based on the
recommendations in the NERC Report,
NERC has begun two Standards
Authorization Request (SAR)
proceedings to revise the standards on
ATC.245 NAESB has also begun a
proceeding to develop business practice
standards to enhance the processing of
transmission service requests, which
affects the ATC calculation.
Staff Preliminary Assessment
591. Staff expressed concerned that
fourteen of the twenty-three Reliability
Standards in this group apply to
regional reliability organization, which
is not a user, owner, or operator of the
Bulk-Power System.
General Comments
592. NERC comments that it has a
team in place to address the regional
reliability organization applicability
issue and will submit an action plan
and schedule in November 2006 for
completing the fill-in-the-blank
standards. NERC expects that it will
take approximately three years to
complete the process, and will prioritize
242 Id.,

71 FR at 32654 and 32667.
is a methodology that first calculates
available capacity on a flowgate-AFC, and transfers
that value into ATC by dividing AFC with the
associated flowgate distribution factor. After ATC is
determined, TTC is calculated from ATC for posting
on OASIS. This method is different from NERC’s
original ATC calculation, where TTC is calculated
in a first step and then used to determine ATC by
reducing TTC with capacity needed for existing
commitments and reserve margins.
244 The NERC Report made recommendations for
greater consistency and greater clarity in the
calculation of ATC/AFC. The task force also
recommended greater communication and
coordination of ATC/AFC information to ensure
that neighboring entities exchange relevant
information. See NERC, Long-Term AFC/ATC Task
Force Final Report (2005) (NERC Report) at 2,
available at: ftp://www.nerc.com/pub/sys/all_updl/
mc/ltatf/LTATF_Final_Report_Revised.pdf.
245 The first SAR proceeding proposes changes to
the existing standards on ATC to, among other
things, further establish consistency in the
calculation of ATC and to increase the clarity of
each transmission provider’s ATC calculation
methodology. The second SAR proceeding proposes
certain changes to NERC’s existing CBM and TRM
standards and calls for greater regional consistency
and transparency in how CBM and TRM are treated
in transmission providers’ ATC calculations.
243 AFC

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standards that require the most
immediate revision.
593. CenterPoint advocates
eliminating many of the MOD
Reliability Standards or consolidating
them into planning or operating
standards. CenterPoint reasons that, to
the extent the process-oriented
Reliability Standards are necessary, the
‘‘fill-in-the-blank’’ standards are
necessary; however, it is impractical to
require that each region use identical
practices in building and validating its
models. CenterPoint adds that, should
the Reliability Standards be approved
by the Commission, ERCOT should be
exempt from those that address transfer
capability because ERCOT does not
have any inter-control area transfers and
does not use the NERC methodologies.
Commission Proposal
594. As we discussed in the Common
Issues section above describing fill-inthe-blank Reliability Standards, we
propose to seek additional information
before acting on the Reliability
Standards that require the regional
reliability organization to provide
criteria on procedures.
595. While we agree with CenterPoint
that some of the MOD Reliability
Standards could be grouped into
planning or operating standards, we will
not propose any such modification, but
rather, leave it to the discretion of the
ERO. Regarding CenterPoint’s
suggestion that ERCOT should be
exempt from Reliability Standards that
address available transfer capability, the
Commission will consider any regional
difference at the time it is submitted by
NERC for Commission review.
Therefore, if ERCOT wishes to request a
regional difference it must do so
through the ERO process.
b. Documentation of Total Transfer
Capability and Available Transfer
Capability Calculation Methodologies
(MOD–001–0)
i. NERC Proposal
596. NERC states that the purpose of
MOD–001–0 is to promote the
consistent and uniform application of
transfer capability calculations among
transmission system users. The
Reliability Standard requires the
regional reliability organizations to
develop their respective methods for
determining TTC and ATC and to make
those methodologies available to others
for review. The Reliability Standard
contains two Requirements directing
each regional reliability organization to:
(1) Develop and document a regional
TTC and ATC methodology in
conjunction with its members; and (2)

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post the most recent version of its TTC
and ATC methodology at a Web site
accessible by NERC, the regional
reliability organizations, and
transmission users.
597. The first Requirement specifies
nine items that the regional reliability
organization must include in its
methodology for determining its TTC
and ATC values. Most of these items
call for descriptions on how TTC and
ATC values are determined and what
assumptions are used. Two items
require the regional reliability
organization to take into account the
reservations and schedules for
transactions occurring inside and
outside the transmission provider’s
system. One item specifies a time and
frequency for calculating and posting
TTC and ATC values.

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ii. Staff Preliminary Assessment
598. Staff identified MOD–001–0 as a
‘‘fill-in-the-blank’’ standard that applies
to the regional reliability organization.
Staff expressed concern that industry
historically used inconsistent
calculation methodologies and stated
that this inconsistency could have an
undue negative impact on competition.
iii. Comments
599. Although NERC acknowledges
that proposed Reliability Standard
MOD–001–0 needs improvement, it
urges that the Commission approve it.
NERC explains that the final version of
the ATC/TTC/AFC Revision SAR
proposes a method for calculating ATC
and requires that specific reliability
practices be incorporated into the ATC
calculation and coordination
methodologies. Further, NERC advises
that a requirement will be added to
enhance documentation of the
calculation.
600. MRO acknowledges that, because
TTC and ATC values must satisfy
certain principles, which balance both
technical and commercial issues from
each of the regions, there may be
differences in the calculation of these
values from the different regions.
However, MRO adds that the parties in
the Eastern Interconnection must agree
to the values, calculations, and
methodologies which flow across the
borders of various regions and system
operators. MRO states that these should
be transparent and agreements should
be based on rational, technical
requirements.
601. ReliabilityFirst submits that it
generally agrees with staff’s evaluation
that, to ensure consistency, procedures
developed by the individual regions
need to be combined. Similarly, TAPS
advises that there are significant flaws

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and undue competitive impacts in the
way the Reliability Standard is currently
proposed. TAPS urges the Commission
to make the calculations related to this
Reliability Standard transparent,
consistent, and regionally-based.
iv. Commission Proposal
602. MOD–001–0 is a ‘‘fill-in-theblank’’ standard that requires each
regional reliability organization to
develop its respective methods for
determining TTC and ATC and to make
those methodologies available to others
for review. Because the regional
procedures have not been submitted to
the Commission, it is not possible to
determine at this time whether MOD–
001–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with MOD–001–0 should continue on
its current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice. Although we do
not propose any action with regard to
MOD–001–0 at this time, we address
our concerns regarding this Reliability
Standard below. The concerns we
discuss below are consistent with the
OATT Reform NOPR.246
603. The Reliability Standard only
requires that the regional reliability
organization document its ATC and TTC
methodology and post that
documentation. The Reliability
Standard does not contain clear
Requirements on how ATC and TTC
should be calculated, which has
resulted in diverse interpretations of
ATC, TTC, and the development of
various calculation methodologies,
modeling assumptions, and data
exchange protocols by various
entities.247 This creates potential
reliability issues and an opportunity to
unduly discriminate against
competitors.
604. Further, the different approaches
in calculation of ATC/AFC,248 TTC, and
lack of clear requirements for
calculation of existing transmission
246 OATT

Reform NOPR at ¶ 155–70.
example, there are two primary ATC
calculation methodologies: the contract path
approach and the flowgate approach. However, the
ATC values that result from application of either
method should largely be the same if consistent
data inputs and modeling assumptions are used.
See OATT Reform NOPR, 71 FR 32653.
248 Available Flowgate Capability is a method
widely used in the Eastern Interconnection but
there is no NERC definition for that term.
247 For

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commitments (ETC) 249 could also create
an undue negative impact on
competition. For example, NERC has
not proposed either a definition or
Reliability Standard on how ETC should
be determined. This could allow
transmission providers to set aside more
capacity for native load than is needed,
and ultimately block capacity that
would otherwise be available to
unaffiliated transmission customers.
This also gives broad discretion to a
transmission provider to determine how
to model power transfers and associated
loop flows that impact the neighboring
systems reliability. We believe that this
Reliability Standard should, at a
minimum, provide a framework for the
ATC, TTC, and ETC calculation.
605. MOD–001–0 requires that the
regional reliability organization develop
and post its methodology on TTC and
ATC, but only requires a narrative
description of a few elements of the TTC
and ATC calculation. We believe that
this Reliability Standard should include
a requirement that applicable entities
make available a comprehensive list of
assumptions and contingencies
underlying ATC and TTC calculations.
We believe that such documentation
should include mathematical
algorithms, process flow diagrams, data
inputs, identification of flowgates, and
modeling assumptions used to perform
the TTC and ATC calculations,
consistent with those proposed in the
OATT Reform NOPR.
606. We are further concerned that the
Reliability Standard does not clearly
define the data to be shared among
transmission service providers. We
believe that MOD–001–0 could be
improved by identifying a detailed list
of information to be shared. This is
consistent with the OATT Reform
NOPR, which proposes that, at a
minimum, the following data should be
exchanged among transmission
providers for the purposes of ATC
modeling: (1) Load levels; (2)
transmission planned and contingency
outages; (3) generation planned and
contingency outages; (4) base generation
dispatch; (5) existing transmission
reservations, including counterflows; (6)
ATC calculation frequency; and (7)
source/sink modeling identification.
607. In addition, the Commission
notes that MOD–001–0 inappropriately
combines the requirements for TTC and
ATC methodology into one Reliability
Standard. TTC and ATC serve two
different purposes and are calculated
through different calculation processes.
We believe that MOD–001–0 should
249 ETC includes transmission capacity set aside
for both native load and transmission reservations.

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address only the ATC and AFC
requirements while the TTC
requirements should be addressed in a
separate Reliability Standard such as
FAC–012–1, as discussed below.
608. The NERC glossary does not
substantially differentiate between the
definition of TTC (as used in MOD–
001–0) 250 and transfer capability (as
used in FAC–012–1).251 Thus, there are
two Reliability Standards to measure
essentially the same thing: One
Reliability Standard calculates TTC
using one set of data and modeling
assumptions presumably for use in
evaluating transmission service
requests, and another Reliability
Standard calculates transfer capability
for in-house use in planning and
operations studies. This will not only
cause confusion, but also opportunities
for discrimination against transmission
customers. We believe that the TTC
calculation methodology should be
addressed under FAC–012–1, which
standardizes transfer capability
methodology.
609. We reiterate our concern
expressed in the OATT Reform NOPR
that modeling assumptions are a crucial
element in the calculation of ATC.252
We believe that NERC should develop a
set of consistent assumptions as a part
of MOD–001–0 for use in ATC and AFC
determinations. Consistent with the
OATT Reform NOPR, we believe that
the assumptions in the calculation of
ATC and AFC should be used
consistently among transmission
providers to the maximum extent
practicable. In general, the Commission
believes that the assumptions used in
the determination of ATC and AFC
should be consistent with those used for
planning the expansion or operation of
the Bulk-Power System. Consequently,
the models for short- and long-term ATC
and AFC calculation should be
developed using consistent assumptions
regarding the load level, generation
dispatch, transmission and generation
facilities maintenance schedules,
250 Total Transfer Capability is defined in the
NERC glossary as ‘‘[t]he amount of electric power
that can be moved or transferred reliably from one
area to another area of the interconnected
transmission systems by way of all transmission
lines (or paths) between those areas under specified
system conditions.’’ NERC glossary at 14.
251 Transfer Capability is defined in NERC
glossary as ‘‘[t]he measure of the ability of
interconnected electric systems to move or transfer
power in a reliable manner from one area to another
over all transmission lines (or paths) between those
areas under specified system conditions. The units
of transfer capability are in terms of electric power,
generally expressed in megawatts (MW). The
transfer capability from ‘Area A’ to ‘Area B’ is not
generally equal to the transfer capability from ‘Area
B’ to ‘Area A.’ ’’ NERC glossary at 15.
252 OATT Reform NOPR at P 166.

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contingency outages and topology as
those used for expansion planning and
operations. Consistent with the OATT
Reform NOPR, we believe that the longterm ATC and AFC models should rely
to the maximum extent possible on the
same assumptions regarding new
transmission and generation facility
additions and retirements as those used
in the planning for expansion.
Specifically, MOD–001–0 should
contain a Requirement that long-term
ATC (one year and longer) be based on
the calculation that uses the same power
flow models, assumptions regarding
load, generation dispatch, special
protection systems, post contingency
switching, and transmission and
generation facility additions and
retirements as those used in the
expansion planning for the same time
frame.
610. Finally, the applicability section
identifies that the Reliability Standard
applies to regional reliability
organizations. Consistent with our
discussion above, we believe that NERC
should identify the applicable entities
in terms of users, owners, and operators
of the Bulk-Power System.253
c. Review of Transmission Service
Provider Total Transfer Capability and
Available Transfer Capability
Calculations and Results (MOD–002–0)
i. NERC Proposal
611. MOD–002–0 concerns the review
of transmission service providers’
compliance with the regional
methodologies for calculating TTC and
ATC. It requires that the regional
reliability organization: (1) Develop and
implement a procedure to periodically
review and ensure that the TTC and
ATC calculations and resulting values
developed by transmission service
providers comply with the regional TTC
and ATC methodology and applicable
regional criteria; (2) document the
results of its periodic review of TTC and
ATC; and (3) provide the results of its
most current reviews to NERC on
request within 30 calendar days.
ii. Staff Preliminary Assessment
612. Staff identified no substantive
issues other than the fact that MOD–
002–0 is a ‘‘fill-in-the-blank’’ standard
and that the standard applies to the
regional reliability organization.
253 We note that our observation here also applies
to MOD–002, MOD–003, MOD–004, MOD–005,
MOD–008, MOD–009, MOD–011, MOD–013, MOD–
014, MOD–015, MOD–016, MOD–024, and MOD–
025.

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64829

iii. Comments
613. The Commission received no
specific comments regarding MOD–002–
0.
iv. Commission Proposal
614. MOD–002–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
each regional reliability organization to
develop and implement a procedure to
periodically review and ensure that a
transmission service provider’s TTC and
ATC calculations comply with regional
TTC and ATC methodologies and
criteria. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether MOD–
002–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to
approve or remand this Reliability
Standard until the regional procedures
are submitted. In the interim,
compliance with MOD–002–0 should
continue on a voluntary basis, and the
Commission considers compliance with
the Reliability Standard to be a matter
of good utility practice.
d. Regional Procedure for Input on Total
Transfer Capability and Available
Transfer Capability Methodologies and
Values (MOD–003–0)
i. NERC Proposal
615. MOD–003–0 defines how a
transmission user can submit its
concerns regarding ATC/TTC
calculation methodologies and values. It
requires each regional reliability
organization to: (1) Develop and
document a procedure on how a
transmission user can input their
concerns or questions regarding TTC
and ATC calculations including the TTC
and ATC values, and how these
concerns will be addressed; and (2)
make its procedure for receiving and
addressing these concerns available to
other regional reliability organizations,
NERC and transmission users on its
Web site.
ii. Staff Preliminary Assessment
616. The Staff Preliminary
Assessment noted that MOD–003–0 is a
‘‘fill-in-the-blank’’ standard. It also
raised concern that MOD–003–0 does
not provide a consistent procedure for
transmission users to input concerns or
questions regarding the methodology for
calculation of TTC and ATC and
resulting TTC and ATC values, nor does
it provide a consistent procedure for

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how these questions or concerns will be
addressed.
iii. Comments
617. The Commission received no
comments regarding MOD–003–0.
iv. Commission Proposal
618. MOD–003–0 is a ‘‘fill-in-theblank’’ standard that requires each
regional reliability organization to
develop and document a procedure to
on how a transmission user can input its
concerns regarding the TTC and ATC
methodologies of a transmission service
provider. Because the regional
procedures have not been submitted to
the Commission, it is not possible to
determine at this time whether MOD–
003–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the regional procedures are
submitted. In the interim, compliance
with MOD–003–0 should continue on a
voluntary basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
e. Documentation of Regional Reliability
Organization Capacity Benefit Margin
Methodologies (MOD–004–0)

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i. NERC Proposal
619. NERC states that the purpose of
MOD–004–0 is to promote the
consistent and uniform application of
transmission transfer capability margin.
MOD–004–0 addresses the development
of a regional methodology for CBM.254
The Reliability Standard requires each
regional reliability organization to: (1)
Develop and document a regional CBM
methodology in conjunction with its
members; and (2) post the most recent
version of its CBM methodology on a
Web site accessible by NERC, regional
reliability organizations, and
transmission users.
620. The first Requirement specifies
ten items that the regional reliability
organization must include and explain
in its CBM calculation method. In
addition, the Reliability Standard
requires that other regional reliability
organization-specific items be explained
254 The NERC glossary defines ‘‘capacity benefit
margin’’ or ‘‘CBM’’ as the amount of firm
transmission transfer capability preserved by a
transmission provider for load serving entities
whose loads are located on the transmission service
provider’s system, to enable access by the load
serving entity to generation from interconnected
systems to meet generation reliability requirements.
NERC glossary at 2.

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along with their use in determining
CBM values. These requirements specify
that calculation of CBM be consistent
with the generation planning criteria,
and that generation outages simulated in
a transmission provider’s CBM
calculation be restricted to those
generators located within the
transmission provider’s system. It is also
required that CBM should be preserved
only for the load within the control area.
The allocation process of the CBM
should be identified. In addition, it
requires that the sum of the CBM values
allocated to all interfaces at one control
area shall not exceed the portion of the
generation reliability requirement that is
to be provided from outside resources.
The remaining items require a
description of the rationale regarding
the assumptions used for CBM
calculation. Finally, it requires a
description of the formal process and
rational for the regional reliability
organization to grant any variances to
individual transmission providers from
the regional reliability organization’s
CBM methodology.
ii. Staff Preliminary Assessment
621. The Staff Preliminary
Assessment noted that MOD–004–0 is a
‘‘fill-in-the-blank’’ standard. Further,
while MOD–004–0 requires each
regional reliability organization to
develop and document a regional CBM
methodology, it does not specify how
CBM is determined and allocated across
transmission paths. Staff expressed
concern that the Reliability Standard
does not address the effect of associated
transmission service requirements and
curtailment provisions on transmission
customers nor does it specify the criteria
used in determining whether or not to
include generation resources, reserves,
and loads in its methodology as
described in four of the Requirements
(R1.5, R1.6, R1.9, and R1.10).
iii. Comments
622. NERC points out that the CBM/
TRM Revisions Standard Authorization
Request (SAR) proposes requiring crisp
and clear calculation documentation
and making various components of the
methodology mandatory to ensure
consistency.
623. TAPS agrees with staff’s
evaluation of MOD–004–0. TAPS states
that the proposed Reliability Standard
has significant flaws and will harm
competition if accepted in its current
form. For example, TAPS refers to the
significant potential for abuse because
transmission providers have flexibility
in the calculation of CBM. Further,
TAPS questions how CBM can be
viewed as a Reliability Standard if it is

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optional to the transmission provider.
TAPS urges the Commission to make
the calculations related to this standard
transparent, consistent, and regionallybased.
iv. Commission Proposal
624. MOD–004–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
each regional reliability organization to
develop and document a regional CBM
methodology. Because the regional CBM
methodologies have not been submitted
to the Commission, it is not possible for
determine at this time whether MOD–
004–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the regional procedures are
submitted. In the interim, compliance
with MOD–004–0 should continue on a
voluntary basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
625. Although we do not propose any
action with regard to MOD–004–0 at
this time, we address our concerns
regarding the Reliability Standard
below.
626. We share TAPS’ concern that
MOD–004–0 may contain significant
flaws and may unduly impact
competition. The Commission
expressed similar concerns with the
CBM calculation in the OATT Reform
NOPR. The lack of consistent criteria
and clarity with regard to the entity on
whose behalf CBM has been set aside
has the potential to result in the
transmission provider setting aside
capacity that it might not otherwise
need to, thus increasing costs for native
load customers and blocking third party
uses of the transmission system.255
627. We also share TAPS’ concern
that the calculations related to this
Reliability Standard must be transparent
and consistent. We are concerned with
the latitude that transmission providers
have when preserving a portion of
transfer capability for CBM. There are
255 The Commission has explained that the pro
forma OATT requires both transmission customers
and transmission providers using the transmission
system to serve network load (including bundled
retail native load) to designate their resources and
loads so that the transmission customers and
transmission providers would have no incentive to
designate network resources above their needs and,
in so doing, tie up valuable transmission capacity.
Aquila Power Corp. v. Entergy Services, Inc., 90
FERC ¶ 61,260, reh’g denied, 92 FERC ¶ 61,064
(2000), reh’g denied, 101 FERC¶ 61,328 (2002), aff’d
sub nom. Entergy Services, Inc. v. FERC, 375 F.3d
1204 (D.C. Cir. 2004).

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no consistent industry-wide standards
for determining how much transfer
capability should be set aside as CBM
and how that amount should be
allocated to interfaces. Therefore, we
believe that MOD–004–0 could be
improved by providing more specific
Requirements on how CBM should be
determined and allocated to interfaces.
628. In response to TAPS’s question
about how CBM can be viewed as a
Reliability Standard if it is optional to
the Transmission Provider, our
understanding is that transmission
providers that opt not to use CBM could
instead set aside transmission margin
(needed to meet the generation
Reliability Standard) either through ETC
or TRM. Obviously, CBM is not the only
way to preserve transmission margin.
However, if the Reliability Standard is
not clear regarding the method to
calculate transmission margin, it may
cause double-counting of transmission
margins and reduction of ATC.
Therefore, we believe that MOD–004–0
could be improved by including a
provision ensuring that CBM, TRM, and
ETC cannot be used for the same
purpose, such as the loss of the identical
generation unit. Without a clear
requirement against double-counting of
margins causing ATC decrease, there is
a possibility that such double-counting
may be used to prevent the nonaffiliated third party’s access to the
transmission system.

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f. Procedure for Verifying Capacity
Benefit Margin Values (MOD–005–0)
i. NERC Proposal
629. The Reliability Standard
specifies the requirements regarding the
periodic review of a transmission
service provider’s adherence to the
regional reliability organization’s CBM
methodology. This Reliability Standard
has three Requirements. The first
Requirement calls for each regional
reliability organization to develop and
implement a procedure to review at
least annually the CBM calculations and
the resulting values determined by
member transmission service providers.
The second Requirement mandates that
the regional reliability organization
document its CBM review procedure
and make it available to NERC on
request within 30 calendar days. The
third Requirement specifies that the
regional reliability organization must
make the results of the most current
CBM review available to NERC on
request, within 30 calendar days. There
are several sub-requirements specifying
the regional reliability organization’s
CBM review process, including an
assurance that the transmission

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provider’s CBM components are
calculated consistently with its
planning criteria, and a Requirement
that CBM values are at least annually
updated and made available to the
regional reliability organization, NERC,
and transmission users.
ii. Staff Preliminary Assessment
630. Staff Preliminary Assessment
noted that although MOD–005–0
requires each regional reliability
organization to review the CBM
calculations and the resulting values, it
does not require a consistent and
uniform calculation of CBM.
iii. Comments
631. The Commission received no
comments regarding MOD–005–0.
iv. Commission Proposal
632. MOD–005–0 is a ‘‘fill-in-theblank’’ standard that requires the
regional reliability organization to
develop and implement a procedure to
review the CBM calculations and the
resulting values and to make the
documentation of the results of the CBM
review available to NERC and others.
Because the regional procedures have
not been submitted to the Commission,
it is not possible to determine at this
time whether MOD–005–0 satisfies the
statutory requirement that a proposed
Reliability Standard be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.’’ Accordingly, the Commission
will not propose to accept or remand
this Reliability Standard until the ERO
submits additional information. In the
interim, compliance with MOD–005–0
should continue on a voluntary basis,
and the Commission considers
compliance with the Reliability
Standard to be a matter of good utility
practice.
g. Procedure for the Use of Capacity
Benefit Margin Values (MOD–006–0)
i. NERC Proposal
633. NERC states that the purpose of
MOD–006–0 is to promote the
consistent and uniform use of
transmission transfer capability margins
calculations among transmission system
users. MOD–006–0 requires a
transmission service provider to
document and post its procedures on
the use of CBM. Specifically, the
Reliability Standard requires that each
transmission service provider document
its procedure explaining scheduling of
energy against CBM. It also requires the
transmission service provider to make
that procedure available on a Web site
accessible by the regional reliability

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64831

organization, NERC, and transmission
users.
ii. Staff Preliminary Assessment
634. Staff stated that it was concerned
that proposed Reliability Standard
MOD–006–0 does not require a
consistent and uniform calculation of
CBM.
iii. Comments
635. The Commission received no
comments regarding MOD–006–0.
iv. Commission Proposal
636. The Commission proposes to
approve MOD–006–0 as mandatory and
enforceable. In addition, we propose to
direct NERC to modify the Reliability
Standard, as discussed below.
637. As discussed above regarding
MOD–004–0, we are concerned that
there is an opportunity to double-count
transmission margins CBM and TRM,
which will result in lower ATC values.
Without a clear requirement against
double-counting margins, this may be
used to prevent non-affiliated third
party access to the transmission system.
Therefore, we propose to direct the ERO
to modify this Reliability Standard to
include a provision that will ensure that
CBM and TRM cannot be used for the
same purpose.
638. Requirement R1.2 of MOD–006–
0 calls for CBM to be used by a loadserving entity that experiences a
generation deficiency only when its
transmission provider simultaneously
experiences ‘‘transmission constraints
relative to imports of energy on its
transmission system.’’ It is our
understanding that a load-serving entity
can experience a generation deficiency
without the simultaneous transmission
constraint on its transmission service
provider’s system. Therefore, we
propose that the ERO modify
Requirement R1.2 so that concurrent
occurrence of transmission constraints
is not a required condition for CBM
usage.
639. Moreover, the Reliability
Standard does not specify how the
generation deficiency is identified. We
propose to direct that the ERO define
‘‘generation deficiency’’ based on a
specific energy emergency alert level
(specified in the EOP Reliability
Standards) that triggers CBM usage.
640. The Commission believes that
CBM should be used only when the
load-serving entity’s local generation
capacity is insufficient to meet
balancing Reliability Standards.
Moreover, a load-serving entity that has
sufficient generation resources within
its balancing authority to meet the
balancing Reliability Standards should

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not need to preserve capacity for CBM
at all. In addition, we believe that CBM
should have a zero value in the
calculation of non-firm ATC. Based on
this guidance, we propose that NERC
should clarify the Requirements to
address when and how CBM can be
used to reduce transmission provider
discretion with regard to CBM usage.
641. Requirement R1.2 of MOD–006–
0 provides that CBM shall only be used
if the load-serving entity calling for its
use is experiencing a generation
deficiency. The applicability section,
however, applies to only transmission
service providers and not load-serving
entities. The Commission believes that
the applicability section should be
expanded to include the entities that
actually use CBM, such as load serving
entities.
642. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
006–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC submit a modification to MOD–
006–0 that: (1) Includes a provision that
will ensure that CBM and TRM are not
used for the same purpose; (2) modifies
Requirement R1.2 so that concurrent
occurrence of generation deficiency and
transmission constraints is not a
required condition for CBM usage; (3)
modifies Requirement R1.2 to define
‘‘generation deficiency’’ based on a
specific energy emergency alert level;
and (4) expands the applicability
section to include the entities that
actually use CBM, such as load serving
entities.
h. Documentation of the Use of Capacity
Benefit Margin (MOD–007–0)

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i. NERC Proposal
643. NERC states that the purpose of
MOD–007–0 is to promote the
consistent use of transmission transfer
capability margin calculations among
transmission system users. MOD–007–0
requires transmission service providers
that use CBM to report and post its use.
This Reliability Standard has two
Requirements. The first Requirement
calls for each transmission provider that
uses CBM, at the request of a loadserving entity, to report that use to the
regional reliability organization, NERC
and the transmission users. The
transmission service provider is not

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required to report the occasions when
CBM is sold on a non-firm basis. The
second Requirement is that, for any use
of CBM concurrent with an energy
emergency situation, the transmission
service provider must disclose and post
circumstances, duration, and the
amount of CBM used on a Web site
accessible by the regional reliability
organization, NERC, and transmission
users.
ii. Staff Preliminary Assessment
644. Staff noted that MOD–007–0
does not specify how CBM should be
preserved, which is important to allow
both transmission providers and
transmission customers to meet their
respective generation reliability criteria.
iii. Comments
645. The Commission received no
comments regarding MOD–007–0.
iv. Commission Proposal
646. The Commission proposes to
approve MOD–007–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
647. Requirement R1 of MOD–007–0
provides that the use of CBM by the
load-serving entity shall be
documented. However, the applicability
section of MOD–007–0 applies to only
transmission service providers and not
load-serving entities. The Commission
believes that the applicability section
should be expanded to include the
entities that actually use CBM, such as
load-serving entities.
648. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
007–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC to submit a modification to
MOD–007–0 that expands the
applicability section to include the
entities that actually use CBM, such as
load-serving entities.
i. Documentation and Content of Each
Regional Transmission Reliability
Margin Methodology (MOD–008–0)
i. NERC Proposal
649. NERC notes that the purpose of
MOD–008–0 is to promote the
consistent application of transmission
transfer capability margin calculations

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among transmission service providers
and transmission owners. MOD–008–0
requires the development and posting of
a regional methodology for TRM, a
transmission capacity that is preserved
to provide reasonable assurance that the
interconnected transmission network
will remain secure under various system
conditions. The Reliability Standard
specifies two Requirements for the
regional reliability organization to: (1)
Develop and document a regional TRM
methodology in conjunction with its
members, and (2) post the most recent
version of its TRM methodology on a
Web site accessible by NERC, the
regional reliability organizations, and
transmission users.
650. The first Requirement specifies
five items that the regional reliability
organization must include and explain
in its TRM calculation method. In
addition, the Reliability Standard allows
other items specific to a regional
reliability organization to be explained
along with their use in determining
TRM values, if such items exist. Some
of these items require the regional
reliability organization to specify TRM
update frequency, describe how TRM
values are accounted for in ATC
calculations, and detail which
uncertainties are accounted for in TRM.
The regional reliability organization
must also describe how transmission
capacity preserved for TRM can be sold
for non-firm services.
ii. Staff Preliminary Assessment
651. Staff noted that although MOD–
008–0 requires each regional reliability
organization to develop and document a
Regional TRM methodology, it does not
specify how TRM is determined and
allocated across transmission paths.
Staff also stated that the Requirement
R1.5 does not specify the criteria for
granting variances from the regional
TRM methodology.
iii. Comments
652. NERC points out that a
Reliability Standard is under
development that will make various
components of the methodology
mandatory to ensure consistency.
653. MRO advocates that MOD–008–
0 should specify the criteria for granting
variances.
iv. Commission Proposal
654. MOD–008–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
each regional reliability organization to
develop a methodology for determining
TRM and to make the methodology
available to others for review. Because
the regional methodologies have not
been submitted to the Commission, it is

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not possible to determine at this time
whether MOD–008–0 satisfies the
statutory requirement that a proposed
Reliability Standard be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.’’ Accordingly, the Commission
will not propose to accept or remand
this Reliability Standard until the ERO
submits additional information. In the
interim, compliance with MOD–008–0
should continue on its current basis,
and the Commission considers
compliance with the Reliability
Standard to be a matter of good utility
practice.
655. Although we do not propose any
action with regard to MOD–008–0 at
this time, we address our concerns
regarding this Reliability Standard
below.
656. We are concerned about the lack
of clear requirements on how TRM
should be calculated and allocated
across the paths. In addition, the lack of
consistent criteria and clarity with
regard to the entity on whose behalf
TRM has been set aside may result in
the transmission provider setting aside
excess capacity, thus increasing costs
for native load customers, and blocking
third party uses of the transmission
system. We seek comments on how
TRM is currently calculated and
allocated across the paths, and what
would be a recommended approach for
the future.
j. Procedure for Verifying Transmission
Reliability Margin Values (MOD–009–0)

sroberts on PROD1PC70 with PROPOSALS

i. NERC Proposal
657. MOD–009–0 specifies the
Requirements for establishing a
procedure for periodic review of a
transmission provider’s adherence to
the relevant regional reliability
organization’s TRM methodology. This
Reliability Standard has three
Requirements. The first Requirement
calls for each regional reliability
organization to develop and implement
a procedure to review TRM calculations
and the resulting values determined by
member transmission providers to
ensure compliance with the regional
TRM methodology. The second
Requirement is that the regional
reliability organization documents its
TRM review procedure and makes that
available to NERC on request within 30
calendar days. The third Requirement
specifies that the reliability regional
organization must make the
documentation of the results of the most
current TRM review available to NERC
on request, within 30 calendar days.

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ii. Staff Preliminary Assessment
658. Staff noted that MOD–009–0
does not provide a consistent procedure
for review of TRM calculations and the
resulting values.
iii. Comments
659. The Commission received no
specific comments regarding MOD–009–
0.
iv. Commission Proposal
660. MOD–009–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
each regional reliability organization to
develop its procedure for review of TRM
calculations and the resulting values.
Because the regional procedures have
not been submitted to the Commission,
it is not possible to determine at this
time whether MOD–009–0 satisfies the
statutory requirement that a proposed
Reliability Standard be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.’’ Accordingly, the Commission
will not propose to accept or remand
this Reliability Standard until the ERO
submits additional information. In the
interim, compliance with MOD–009–0
should continue on its current basis,
and the Commission considers
compliance with the Reliability
Standard to be a matter of good utility
practice.
k. Steady-State Data for Modeling and
Simulation of Interconnected
Transmission System (MOD–010–0)
i. NERC Proposal
661. The purpose of this Reliability
Standard is to establish consistent data
requirements, reporting procedures, and
system models to be used in the
reliability analysis. MOD–010–0
requires the transmission owner,
transmission planner, generator owner,
and resource planner to provide steadystate data, such as equipment
characteristics, system data, and
existing and future interchange
schedules, to the regional reliability
organization, NERC, and entities
specified in Requirement R1 of MOD–
011–0. Data is to be provided within the
determined time schedule or upon
request if no time schedule exists.
ii. Staff Preliminary Assessment
662. Staff noted that MOD–010–0
does not include the planning authority
as an applicable entity. The inclusion of
the planning authority is necessary in
the applicability section of the
Reliability Standard because the
planning authority is the entity
responsible for the coordination and
integration of transmission facilities and

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64833

resource plans, as well as one of the
entities responsible for the integrity and
consistency of the data.
iii. Comments
663. MRO and ReliabilityFirst state
that they generally agree with staff’s
evaluation of MOD–010–0. However, in
response to the staff comment regarding
inappropriate exclusion of the planning
authority from the Reliability Standard’s
applicability, ReliabilityFirst points out
that the information required by the
Reliability Standard originates with the
transmission planner and resource
planner who, ultimately, provide such
information to the planning authority.
Similarly, PG&E states that a planning
authority does not develop, and cannot
provide such information and is rightly
not included in the applicability section
of the standard. PG&E explains that
MOD–010–0 requires transmission
owners, transmission planners,
generator owners, and resource planners
to provide appropriate equipment
characteristics, system data, and
existing and future interchange
schedules in compliance with
Interconnection regional steady-state or
dynamic modeling and simulation data
requirements and reporting procedures.
iv. Commission Proposal
664. The Commission proposes to
approve MOD–010–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
665. We propose that MOD–010–0
should add a new requirement to have
the transmission owners also provide
the list of the contingencies they use in
performing system operation and
planning studies. We believe that access
to such information will enable
neighboring systems to accurately study
their effects on their own systems.
666. In addition, we propose that the
Reliability Standard should be modified
to apply to the planning authority. The
planning authority is the entity
responsible for coordination and
integration of transmission facilities and
resource plans, as well as one of the
entities responsible for the integrity and
consistency of the data. We disagree
with commenters that the planning
authority should be omitted from the
applicability section because it merely
gets the data from the others. We believe
that the planning authority plays a
significant role in integration of the
data.
667. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the

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purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
010–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC to submit a modification to
MOD–010–0 that: (1) Adds a new
requirement for transmission owners to
provide the list of contingencies they
use in performing system operation and
planning studies; and (2) expands the
applicability section to include the
planning authority.
l. Maintenance and Distribution of
Steady-State Data Requirements and
Reporting Procedures (MOD–011–0)
i. NERC Proposal
668. The purpose of MOD–011–0 is to
establish consistent data requirements,
reporting procedures, and system
models to be used in the reliability
analysis. MOD–011–0 requires the
regional reliability organization within
an Interconnection to develop
comprehensive steady-state data
requirements and reporting procedures
needed to model and analyze the
steady-state conditions for each of the
three NERC Interconnections. The
regional reliability organizations within
an Interconnection are required to:
(1) Document their Interconnection’s
data requirements and reporting
procedures;
(2) Review the data requirements and
reporting procedures at least every five
years; and
(3) Make the data requirements and
reporting procedures available on
request to the regional reliability
organizations, NERC, and all users of
the interconnected transmission system.
ii. Staff Preliminary Assessment

sroberts on PROD1PC70 with PROPOSALS

669. Staff noted that MOD–011–0,
identified as a ‘‘fill-in-the-blank’’
standard, does not include the planning
authority in the Requirements section.
The planning authority is the entity
responsible for coordination and
integration of transmission facilities and
resource plans, as well as one of the
entities responsible for the integrity and
consistency of the data.
iii. Comments
670. PG&E comments that MOD–011–
0 does not need to be modified because
the appropriate planning authority will
be a part of the regional reliability
organization.

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iv. Commission Proposal
671. As mentioned above, MOD–011–
0 is a ‘‘fill-in-the-blank’’ standard that
requires the regional reliability
organizations within an Interconnection
to develop comprehensive steady-state
data requirements and reporting
procedures needed to model and
analyze the steady-state conditions for
each of the three NERC
Interconnections. Because the regional
methodologies have not been submitted
to the Commission, it is not possible to
determine at this time whether MOD–
011–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with MOD–011–0 should continue on
its current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
672. As we noted in the discussion of
MOD–010–0, we believe that the
planning authority plays a significant
role in integration of data and should
also be included in the applicability
section of MOD–011–0.
m. Dynamics Data for Modeling and
Simulation of the Interconnected
Transmission System (MOD–012–0)
i. NERC Proposal
673. The purpose of MOD–012–0 is to
establish consistent data requirements,
reporting procedures, and system
models to be used in the reliability
analysis. MOD–012–0 requires
transmission owners, transmission
planners, generator owners, and
resource planners to provide dynamic
system modeling and simulation data,
such as equipment characteristics and
system data, to the regional reliability
organization, NERC, and entities
specified in MOD–013–0, Requirement
R1, within a pre-determined time
schedule or upon request if no time
schedule exists.
ii. Staff Preliminary Assessment
674. Staff stated that proposed
Reliability Standard MOD–012–0 does
not apply to the planning authority.
However, the planning authority is the
entity responsible for the coordination
and integration of transmission facilities
and resource plans, as well as one of the
entities responsible for the integrity and
consistency of the data.

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iii. Comments
675. MRO agrees with staff that the
planning authority should be included
in MOD–012–0. In contrast, PG&E
comments that MOD–012–0 does not
need to be modified, as found by staff’s
evaluation. Since the appropriate
planning authority is already a part of
the regional reliability organization,
specific inclusion of the planning
authority within the Reliability
Standard is unnecessary. PG&E explains
that, because MOD–012–0 requires the
regional reliability organization within
an Interconnection to develop data
requirements and reporting procedures
needed to model and analyze the
conditions for each Interconnection, it
already provides for appropriate
participation by the planning authority.
iv. Commission Proposal
676. We propose that MOD–012–0
add a new requirement for transmission
owners to provide the list of faults or
disturbances they use in performing
dynamic stability analysis. We believe
that access to such information will
enable neighboring systems to
accurately study their effects on their
own systems. As we noted in the
discussions of MOD–010–0 and MOD–
11–0, we believe that the planning
authority plays a significant role in
integration of data and should also be
included in the applicability section of
MOD–012–0.
677. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
012–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC submit a modification to MOD–
012–0 that: (1) adds a new requirement
for transmission owners to provide the
list of faults or disturbances they use in
performing dynamic stability analysis;
and (2) expands the applicability
section to include the planning
authority.
n. Maintenance and Distribution of
Dynamics Data Requirements and
Reporting Procedures (MOD–013–1)
i. NERC Proposal
678. The purpose of MOD–013–1 is to
establish consistent data requirements,
reporting procedures, and system
models to be used in reliability analysis.
MOD–013–1 requires the regional

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reliability organizations within an
Interconnection to develop
comprehensive dynamics data
requirements and reporting procedures
needed to model and analyze the
dynamic behavior and response of each
of the three NERC Interconnections.
More specifically, the regional
reliability organization, in coordination
with its transmission owners,
transmission planners, generator
owners, and resource planners within
an Interconnection, is required to: (1)
Participate in development of
documentation for their Interconnection
data requirements and reporting
procedures; (2) participate in the review
of those data requirements and reporting
procedures (at least every five years);
and (3) make the data requirements and
reporting procedures available on
request to the regional reliability
organizations, NERC, and all users of
the interconnected transmission system
on request.
679. The proposed Reliability
Standard specifies the types of dynamic
data that should be included. For
example, it specifies that dynamics data
pertaining to generating units,
synchronous condensers, other devices
that dynamically respond during
disturbances, and dynamics data
representing load characteristics should
be provided. In addition, the Reliability
Standard requires that dynamics data be
consistent with the steady state data
supplied according to MOD–010–0,
Requirement R1.
680. NERC’s August 28, 2006
Supplemental Filing includes a revised
version of MOD–013, designated MOD–
013–1. MOD–013–1 has an additional
Requirement to provide design data for
the new or refurbished excitation
systems.

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ii. Staff Preliminary Assessment
681. Staff stated that proposed
Reliability Standard does not include
the planning authority in the
applicability section. The inclusion of
the planning authority is necessary in
the applicability section of the
Reliability Standard because the
planning authority is the entity
responsible for coordinating and
integrating transmission facilities and
resource plans, as well as one of the
entities responsible for the integrity and
consistency of the data.256
iii. Comments
682. NERC acknowledges that
planning authorities also have
256 Although the Staff Preliminary Assessment
addresses concerns regarding the MOD–013–0,
many of the same concerns apply to MOD–013–1
as well.

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responsibilities under the Reliability
Standard and the applicability section
should be revised to reflect that. PG&E,
on the other hand, asserts that the
proposed Reliability Standard does not
need to be modified, because the
appropriate planning authority is a part
of the regional reliability organization,
specific inclusion of the planning
authority within the Reliability
Standard is unnecessary.
683. PG&E adds that Requirement
R1.1.1, which allows for the use of
estimated or typical manufacturer’s data
on pre-1990 units to model dynamic
behavior when unit-specific data is
unavailable, is arbitrary in imposing the
1990 cut-off. PG&E asserts that difficulty
in obtaining unit specific data is not
limited to the age of the unit but also
unit configuration. As a result, PG&E
recommends that the 1990 cut-off be
removed from the proposed Reliability
Standard and that the Reliability
Standard be revised to allow the use of
estimated or typical manufacturer data
where unit specific data is impractical
to obtain.
iv. Commission Proposal
684. MOD–013–1 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
the regional reliability organizations
within an Interconnection to develop
comprehensive dynamics data
requirements and reporting procedures
needed to model and analyze the
dynamic behavior or response for each
of the three NERC Interconnections.
Because the regional methodologies
have not been submitted to the
Commission, it is not possible to
determine at this time whether the
proposed Reliability Standard satisfies
the statutory requirement that it be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with the proposed Reliability Standard
should continue, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice. Although we do
not propose any action with regard to
MOD–013–1 at this time, we address
our concerns regarding this Reliability
Standard below.
685. We share PG&E’s concern
regarding the 1990 cut off date that the
difficulty in obtaining unit-specific data
is not limited to the age, but may also
be due to other factors such as unit
configuration. The Commission seeks
comment whether it is reasonable to
permit entities to estimate dynamics

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64835

data if they are unable to obtain unit
specific data for any reason.
686. We agree with NERC that the
Reliability Standard should apply to the
planning authority.
o. Development of Steady-State System
Models (MOD–014–0)
i. NERC Proposal
687. The purpose of MOD–014–0 is to
establish consistent data requirements,
reporting procedures, and steady-state
system models to be used in reliability
analysis. The Reliability Standard
requires the regional reliability
organizations within each
Interconnection to coordinate and
jointly develop and maintain a library of
solved Interconnection-specific steadystate models. These models are to
include near- and long-term planning
horizons representing system conditions
for various demand levels. The yearly
models represent various seasonal
conditions, usually for on- and off-peak
load. The models are to be updated
annually. The regional reliability
organizations are required to submit the
most recent models to NERC in
accordance with a set schedule.
ii. Staff Preliminary Assessment
688. Staff pointed out that while the
Reliability Standard requires the
development of steady-state models, it
does not require periodic verification or
appropriate modification of models
against field data in accordance with
Recommendation No. 24 of the Blackout
Report.257
iii. Comments
689. NERC comments that the NERC
Multiregional Modeling Working Group
(MMWG) is following recommendations
from the Blackout Report that involve
verifying powerflow models and
databases, which include benchmarking
to actual load levels and the periodic
testing of MW, MVAR, and dynamic
controls of generators.
690. MRO, National Grid and ISO/
RTO Council agree with staff’s
evaluation of MOD–014–0.
ReliabilityFirst submits that it generally
agrees with staff’s evaluation of MOD–
014–0 that, to ensure consistency,
procedures developed by the individual
regions need to be merged. In contrast,
CenterPoint maintains that it is
impractical to require each region to use
identical practices in building and
validating its models.
iv. Commission Proposal
691. MOD–014–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
257 Blackout

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the regional reliability organizations
within an Interconnection to develop,
coordinate and maintain a library of
solved Interconnection-specific steadystate models. Because the regional
procedures have not been submitted to
the Commission, it is not possible to
determine at this time whether MOD–
014–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with MOD–014–0 should continue, and
the Commission considers compliance
with the Reliability Standard to be a
matter of good utility practice.
692. Although we do not propose any
action with regard to MOD–014–0 at
this time, we address our concerns
regarding this Reliability Standard
below.
693. The Reliability Standard does not
require periodic verification or
appropriate modification of models
against field data in accordance with
Recommendation No. 24 of the Blackout
Report.258 We understand that the NERC
MMWG that is incorporating
recommendations from the Blackout
Report is developing models only for
the Eastern Interconnection. We believe
that a Requirement to verify that steady
state models are accurate should be a
part of this Reliability Standard so that
it applies to all three Interconnections.
694. In addition, we are concerned
about creating a duplicate effort if both
the transmission owner and the regional
reliability organization separately
develop the steady-state base cases
required for the FERC Form 715 filing
and for MOD–014–0. We believe that
this Reliability Standard should contain
a Requirement specifying the time
period and the planning years to be
identical to those found in FERC Form
715.259 We also seek comments on any
incompatibility between our

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258 Blackout

Report at 160.
259 FERC Form 715 is available at http://
www.ferc.gov/docs-filing/eforms.asp#715. FERC
Form 715 specific instructions on Part 2, power
flow base cases:
‘‘The input data to the solved power flow base
cases must be forward-looking. For example, the
power flow base cases submitted and made
available might include: 1. One, two, five and tenyear forecasts under summer and winter peak
conditions and 2. A one-year forecast under light
load/heavy transfers condition. This example is
similar to a schedule of base cases proposed by
NERC’s Multiregional Modeling Working Group for
development at the time this form was created.’’

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requirements under FERC Form 715 and
MOD–014–0.
p. Development of Dynamics System
Models (MOD–015–0)
i. NERC Proposal
695. The purpose of MOD–015–0 is to
establish consistent data requirements,
reporting procedures, and system
models to be used in the reliability
analysis. The Reliability Standard
requires the regional reliability
organizations within each
Interconnection to coordinate and
jointly develop and maintain a library of
initialized (with no faults and
disturbances) Interconnection-specific
dynamic system models. These models
represent near-term years and the years
chosen from the longer-term planning
horizon. The models are to be updated
annually. The regional reliability
organizations are required to submit the
most recent models to NERC in
accordance with a set schedule.
ii. Staff Preliminary Assessment
696. Staff noted that, while the
Reliability Standard requires the
development of dynamic models, it does
not require periodic verification or
appropriate modification of models
against field data in accordance with
Recommendation No. 24 of the Blackout
Report.260
iii. Comments
697. NERC comments that testing
should be done to periodically verify
that system dynamics models are
accurate.
698. ISO/RTO Council and MRO agree
with staff’s evaluation of Reliability
Standard MOD–015–0. MRO suggests
that, should a Regional Entity be
required to perform this responsibility,
it should be required in the Regional
Entity’s delegation agreement.
iv. Commission Proposal
699. MOD–015–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
the regional reliability organizations
within an Interconnection to develop,
coordinate and maintain a library of
initialized Interconnection-specific
dynamics system models. Because the
applicable regional procedures have not
been submitted to the Commission, it is
not possible to determine at this time
whether MOD–015–0 satisfies the
statutory requirement that a proposed
Reliability Standard be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.’’ Accordingly, the Commission
will not propose to accept or remand
260 Blackout

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this Reliability Standard until the ERO
submits additional information. In the
interim, compliance with MOD–015–0
should continue on a voluntary basis,
and the Commission considers
compliance with the Reliability
Standard to be a matter of good utility
practice.
700. Although we do not propose any
action with regard to MOD–015–0 at
this time, we address our concerns
regarding this Reliability Standard
below.
701. We agree with NERC and believe
that a Requirement to verify accuracy of
system dynamics models should be a
part of this Reliability Standard.261
q. Documentation of Data Reporting
Requirements for Actual and Forecast
Demands, Net Energy for Load,
Controllable Demand—Side
Management (MOD–016–1)
i. NERC Proposal
702. The purpose of MOD–016–1 is to
ensure that past and forecasted demand
data are available for validation of past
events and future system assessments.
MOD–016–1 requires the planning
authority and the regional reliability
organization to have documentation
identifying the scope and details of the
actual and forecast demand and load
data, and controllable Demand-Side
Management (DSM) data to be reported
for system modeling and reliability
analysis. These requirements are to
ensure that consistent data is supplied
for various TPL and MOD Reliability
Standards that address system models
and simulations.262
ii. Staff Preliminary Assessment
703. Staff noted that the proposed
Reliability Standard does not include
the transmission planner in the
applicability section. The transmission
planner is one of the entities involved
in assuring the integrity and consistency
of the load, energy, and DSM data.
iii. Comments
704. The Commission received no
specific comments regarding this
Reliability Standard.
iv. Commission Proposal
705. We propose that the Reliability
Standard be modified to include
261 See ERCOT report ‘‘August 19, 2004 Forney
Plant Trip Event Simulation’’ prepared by the
ERCOT Reliability and Operations Subcommittee
by ERCOT Dynamics Working Group.
262 On August 28, 2006, NERC submitted MOD–
016–1 for approval, which replaces MOD–016–0.
MOD–016–1 contains an additional Requirement
that each load-serving entity must count its
customer demand values only once. MOD–016–1
has also an improved set of Measures and Levels
of Non-compliance.

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transmission planner in the
applicability section because the
transmission planner is one of the
entities involved in assuring the
integrity and consistency of the load,
energy, and DSM data.263
706. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
016–1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC submit a modification to MOD–
016–1 that expands the applicability
section to include the transmission
planner.
r. Aggregated Actual and Forecast
Demands and Net Energy for Load
(MOD–017–0)
i. NERC Proposal
707. The purpose of MOD–017–0 is to
ensure that past and forecasted demand
data are available for validation of past
events and future system assessment.
The Reliability Standard requires the
load-serving entities, planning
authorities and resource planners to
annually provide aggregated
information on: (1) Integrated hourly
demands; (2) actual monthly and annual
peak demand (MW) and net load energy
(GWh) for the prior year; (3) monthly
peak demand forecast and net load
energy for the next two years; and (4)
annual peak demand forecast (summer
and winter) and annual net load energy
for at least five and up to ten years into
the future.
ii. Staff Preliminary Assessment
708. Staff stated that MOD–017–0
does not require a consistent
methodology in validating and
forecasting demand. Specifically, there
are no Requirements to report the
accuracy, error, and bias of load
forecasts.

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iii. Comments
709. ReliabilityFirst submits that it
generally agrees with staff’s evaluation
of MOD–017–0. It also points out that
263 DSM may include control of electric supply to
individual appliances or equipment on customer
premises, interruptible/curtailable load, demand
bidding/buy-back programs, emergency demand
response programs, capacity market programs,
ancillary service market programs, and distributed
generation (including solar PV, Combined Heat and
Power facilities, and micro turbines). See Demand
Response Report, Executive Summary at viii.

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some of the data related to the
Reliability Standard are already
addressed in U.S. Energy Information
Administration (EIA) reporting
requirements.
iv. Commission Proposal
710. The Commission proposes to
approve MOD–017–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
711. The Commission notes that load
forecasts for most of the nation are
driven by hot and humid weather. Most
forecasts are ‘‘normalized’’ to a standard
temperature and humidity condition to
avoid the variations caused by real
weather conditions. It is important to
know these conditions when viewing
the actual peak loads and in predicting
what peak loads will be in the future.
The Commission proposes to add a
Requirement to provide temperature
and humidity information that is
associated with peak load data.
712. MOD–017–0 does not require a
consistent methodology in validating
and forecasting demand, specifically in
reporting the accuracy, error, and bias of
load forecasts by load serving entity,
planning authority, and resource
planner. This can lead to
inconsistencies in modeling the load
data for transmission planning and ATC
analysis. We believe that
underestimated load data (modeled in
steady-state cases for future years) may
not adequately indicate a need for
operating procedures, or system
reinforcements, and can potentially
jeopardize system reliability.
713. We propose that the Reliability
Standard have additional requirements
for reporting the accuracy, error, and
bias of load forecasts compared to actual
loads with due regard to temperature
and humidity variations.264
714. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
017–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to MOD–
017–0 that includes new Requirements
264 The Commission expects that the data
provided in response to MOD–017–0 will be
consistent with data reported in MOD–019–0,
MOD–020–0 and MOD–021–0.

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for: (1) reporting of temperature and
humidity along with the peak load; and
(2) reporting of the accuracy, error, and
bias of load forecasts compared to actual
loads with due regard to temperature
and humidity variations.
s. Treatment of Nonmember Demand
Data and How Uncertainties Are
Addressed in the Forecasts of Demand
and Energy for Load (MOD–018–0)
i. NERC Proposal
715. The purpose of MOD–018–0 is to
ensure that past and forecasted demand
data are available for validation of past
events and future system assessment.
The Reliability Standard requires that
the load-serving entities, planning
authorities, transmission planners, and
resource planners each submit a load
data report which: (1) Indicates whether
the demand data includes the regional
reliability organization non-members’
demand, and (2) addresses how
assumptions, methods, and
uncertainties are treated. The Reliability
Standard also requires that each of the
load-serving entities, planning
authorities, transmission planners, and
resource planners report the above
information to NERC, the regional
reliability organization, and the loadserving entities, planning authorities,
transmission planners, and resource
planners on request.
ii. Staff Preliminary Assessment
716. Staff raised no specific concerns
regarding MOD–018–0.
iii. Comments
717. The Commission received no
specific comments regarding
MOD–018–0.
iv. Commission Proposal
718. The Commission proposes to
approve MOD–018–0 as mandatory and
enforceable. The Requirements set forth
in MOD–018–0 are sufficiently clear and
objective as to provide guidance for
compliance.
t. Reporting of Interruptible Demands
and Direct Control Load Management
(MOD–019–0)
i. NERC Proposal
719. The purpose of MOD–019–0 is to
ensure that past and forecasted demand
data are available for validation of past
events and future system assessment.
The Reliability Standard requires that
the load-serving entities, planning
authorities, transmission planners, and
resource planners annually provide
their forecasts of interruptible demands
and direct control load management to
NERC, the regional reliability

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organization, and other entities as
specified in MOD–016–1, Requirement
R1. The data should contain the
forecasts for at least five years, and up
to ten years.
ii. Staff Preliminary Assessment
720. Staff stated that proposed
Reliability Standard MOD–019–0 does
not require a consistent methodology to
validate and forecast interruptible
demand. Specifically, there are no
Requirements to report the accuracy,
error and bias of load forecasts.
iii. Comments
721. The Commission received no
specific comments regarding
MOD–019–0.
iv. Commission Proposal
722. MOD–019–0 does not require
reporting of the accuracy, error and bias
of controllable load 265 forecast.
Therefore, we propose that NERC
develop a Requirement for a consistent
approach to controllable load forecast
and verification as well as reporting of
the associated accuracy, error and bias
of controllable load forecast.
723. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
019–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose to direct that
NERC submit a modification to MOD–
019–0 that includes new Requirements
for reporting of the accuracy, error and
bias of controllable load forecast.
u. Providing Interruptible Demands and
Direct Control Load Management Data
to System Operators and Reliability
Coordinators (MOD–020–0)

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i. NERC Proposal
724. The purpose of MOD–020–0 is to
ensure that past and forecasted demand
data are available for validation of past
events and future system assessment.
The Reliability Standard requires that
each load-serving entity, planning
authority, transmission planner, and
resource planner identifies its amount
of: (1) Interruptible demand and (2)
direct control load management (DCLM)
to the transmission operators, balancing
265 Whereas MOD–019–0 and MOD–020–0 use
two separate terms interruptible load and Direct
Control Load Management, NOPR uses
‘‘controllable load’’ to refer to both of them.

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authorities, and reliability coordinators
on request.
ii. Staff Preliminary Assessment
725. Staff found that proposed
Reliability Standard MOD–020–0 does
not require a consistent methodology in
validating and forecasting interruptible
demand. Specifically, there are no
Requirements to report the accuracy,
error and bias of load forecasts.
iii. Comments
726. The Commission received no
specific comments regarding
MOD–020–0.
iv. Commission Proposal
727. The Commission proposes to
approve MOD–020–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
728. For the same reasons as
discussed in MOD–017, the Commission
proposes to direct NERC to add
requirements concerning the reporting
of the accuracy, error, and bias of
controllable load forecasts.
729. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
019–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC submit a modification to MOD–
020–0 that includes a new requirement
concerning the reporting of the
accuracy, error, and bias of controllable
load forecasts.
v. Documentation of the Accounting
Methodology for the Effects of
Controllable Demand-Side Management
in Demand and Energy Forecasts (MOD–
021–0)
i. NERC Proposal
730. The purpose of MOD–021–0 is to
ensure that past and forecasted demand
data are available for validation of past
events and future system assessment.
The Reliability Standard requires the
load-serving entities, transmission
planners, and resource planners to
clearly document how each addresses
the demand and energy effects of DSM
programs . The Reliability Standard also
requires the load-serving entities,
transmission planners, and resource
planners to each include information
detailing how Demand-Side

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Management measures are addressed in
the forecasts of its peak demand and
annual net energy for load in the data
reporting procedures of MOD–016–0,
Requirement R1. Lastly, MOD–021–0
requires load-serving entities,
transmission planners, and resource
planners to each document the
treatment of its DSM programs, which is
to be made available to NERC on
request.
ii. Staff Preliminary Assessment
731. Staff stated that proposed
Reliability Standard MOD–021–0 does
not require a consistent methodology in
validating and forecasting demand.
Specifically, there are no Requirements
to report the accuracy, error and bias of
load forecasts.
iii. Comments
732. The Commission received no
specific comments regarding
MOD–021–0.
iv. Commission Proposal
733. The Commission proposes to
approve MOD–021–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
734. MOD–021–0 does not require a
consistent methodology in validating
and forecasting demand, specifically in
reporting information detailing how
DSM measures are addressed in the
forecasts. We propose that NERC modify
MOD–021–0 to contain Requirements
standardizing principles on reporting
and validation of DSM program
information. While the title of this
Reliability Standard includes
‘‘controllable demand side
management,’’ the Requirements only
relate to demand side management in
general. We have a similar concern with
the purpose statement of this Reliability
Standard. Thus, we propose that the
ERO modify the title and purpose
statement consistent with the
Requirements.
735. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard MOD–
019–0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, we propose directing that
NERC submit a modification to MOD–
021–0 that: (1) Includes a Requirement
standardizing principles on reporting

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and validation of DSM program
information; and (2) modifies the title
and purpose statement to remove the
word ‘‘controllable,’’ consistent with the
Requirements.
w. Verification of Generator Gross and
Net Real Power Capability (MOD–024–
1)
i. NERC Proposal
736. NERC states that the purpose of
MOD–024–1 is to ensure that accurate
information on generation gross and net
real power capability is used for
reliability assessment. The Reliability
Standard requires the regional reliability
organization to establish and maintain
procedures to address verification of
generator gross and net real power
capability. The Reliability Standard also
requires the regional reliability
organization to provide its generator
gross and net real power capability
verification and reporting procedures,
and any changes to those procedures, to
the generation owners, generation
operators, transmission operators,
planning authorities, and transmission
planners affected by those procedures.
Finally, MOD–024–1 requires the
generator owners to follow their
regional reliability organization’s
procedure for verifying and reporting
gross and net real power generating
capability.
ii. Staff Preliminary Assessment
737. Staff noted that while the
Reliability Standard requires the
regional reliability organization to
establish and maintain procedures to
address verification of generator gross
and net real power capability, the
Reliability Standard does not define test
conditions, e.g., ambient temperature,
river water temperature, or
methodologies for calculating de-rating
factors for conditions such as higher
ambient temperatures than the test
temperature.

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iii. Comments
738. NERC points out that
Requirement R1.3 of MOD–024–1
includes data verification of any
applicable conditions under which the
data should be verified. MRO and
ReliabilityFirst note that MOD–024–1 is
currently undergoing field-testing.
iv. Commission Proposal
739. MOD–024–1 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
the regional reliability organizations to
establish and maintain procedures to
address verification of generator gross
and net real power capability. Because
the applicable regional procedures have
not been submitted to the Commission,

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it is not possible to determine at this
time whether MOD–024–1 satisfies the
statutory requirement that a proposed
Reliability Standard be ‘‘just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.’’ Accordingly, the Commission
will not propose to accept or remand
this Reliability Standard until the ERO
submits additional information. In the
interim, compliance with MOD–24–1
should continue on its current basis,
and the Commission considers
compliance with the Reliability
Standard to be a matter of good utility
practice.
740. Although we do not propose any
action with regard to MOD–024–1 at
this time, we address our concerns
regarding this Reliability Standard
below.
741. We believe that the Reliability
Standard is not sufficiently clear
because it does not define the test
conditions and methodologies for
calculating de-rating factors. Such
specificity would provide consistency
in reporting of generator gross and net
real power capability. In addition, we
note that the Requirement R2 states that
the ‘‘Regional Reliability Organization
shall provide generator gross and net
real power capability verification within
30 calendar days of approval.’’ It is not
clear what approval is required and it is
also not clear when the 30 days period
starts. Taking into account that the
Reliability Standard is currently
undergoing field-testing, we believe that
more information will be available at
the time the NOPR comments are due.
x. Verification of Generator Gross and
Net Reactive Power Capability (MOD–
025–1)
i. NERC Proposal
742. NERC states that the purpose of
MOD–025–1 is to ensure that accurate
information on generation gross and net
reactive power capability is used for
reliability assessment. The Reliability
Standard requires the regional reliability
organization to establish and maintain
procedures to address verification of
generator gross and net reactive power
capability. The Reliability Standard also
requires the regional reliability
organization to provide its generator
gross and net reactive power capability
verification and reporting procedures,
and any changes to those procedures, to
the generator owners, generator
operators, transmission operators,
planning authorities, and transmission
planners affected by the procedure
within 30 calendar days of approval.
Lastly, MOD–025–1 requires the
generator owner to follow its regional

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reliability organization’s procedures for
verifying and reporting its gross and net
reactive power generating capability.
ii. Staff Preliminary Assessment
743. Staff identified MOD–025–1 as a
‘‘fill-in-the-blank’’ standard that applies
to the regional reliability organization.
iii. Comments
744. CenterPoint suggests that MOD–
025–1 does not adequately address the
verification of generator reactive
capability. It explains that the
Reliability Standard requires a generator
to provide certain reactive power
capability at the unit’s full MW loading.
However, it points out that most units
rarely operate at full MW loading,
making it unclear what reactive
capability is required over a unit’s real
power (MW) operating range.
CenterPoint suggests that MOD–025–1
would be clearer if it requires a
minimum reactive (MVAR) capability
throughout a unit’s real power operating
range.
745. MRO and ReliabilityFirst note
that MOD–025–1 is currently
undergoing field-testing.
iv. Commission Proposal
746. The MOD–025–1 is a ‘‘fill-in-theblank’’ Reliability Standard that requires
the regional reliability organizations to
establish and maintain procedures to
address verification of generator gross
and net reactive power capability.
Because the applicable regional
procedures have not been submitted to
the Commission, it is not possible to
determine at this time whether MOD–
025–1 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with MOD–25–1 should continue on its
current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
747. Although we do not propose any
action with regard to MOD–025–1 at
this time, we address our concerns
regarding this Reliability Standard
below.
748. We agree with CenterPoint that
MOD–025–1 could be clearer. This
could be accomplished by requiring a
minimum reactive power (MVAR)
capability throughout a unit’s real
power operating range. In addition, we
note that the Requirement R2 states that
the ‘‘Regional Reliability Organization

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shall provide generator gross and net
real power capability verification within
30 calendar days of approval.’’ It is not
clear what approval is required and it is
also not clear when the 30 days period
starts. Taking into account that the
Reliability Standard is currently
undergoing field-testing, we believe that
more information will be available at
the time the NOPR comments are due.
9. PER: Personnel Performance, Training
and Qualifications
a. Overview
749. The four proposed Personnel
Performance, Training and
Qualifications (PER) Reliability
Standards are applicable to transmission
operators, reliability coordinators and
balancing authorities with the intention
of ensuring the safe and reliable
operation of the interconnected grid
through the retention of suitably trained
and qualified personnel in positions
that can impact the reliable operation of
the Bulk-Power System. The proposed
PER Reliability Standards address: (1)
Operating personnel responsibility and
authority; (2) operating personnel
training; (3) operating personnel
credentials; and (4) reliability
coordination staffing.
b. Operating Personnel Responsibility
and Authority (PER–001–0)
i. NERC Proposal
750. PER–001–0 ensures the energy
balance and transmission reliability of
the Interconnected grid by requiring that
transmission operator and balancing
authority personnel have the
responsibility and authority to direct
actions in real-time. In practical terms,
NERC asserts that the proposed
Reliability Standard requires operating
personnel who are responsible for
operating the Bulk-Power System to
have the authority to take action when
they believe it is necessary.266
Additionally, PER–001–0 requires clear
documentation that operating personnel
have the responsibility and authority to
implement real-time action to ensure
the stable and reliable operation of the
Bulk-Power System.

iv. Commission Proposal
753. PER–001–0 requires that each
transmission operator and balancing
authority provide operating personnel
with the responsibility and authority to
implement real-time actions to ensure
the stable and reliable operation of the
Bulk Electric System. Documentation
designating the job description and
responsibilities and authorities of each
operating position of a transmission
operator and balancing authority must
be articulated in ‘‘clear and
unambiguous language.’’ 268 Further, the
required documentation should be
readily available in the control room to
all operating personnel.
754. We believe that the proposed
Reliability Standard clarifies the level of
responsibility and authority that the
transmission operator and the balancing
authority have to act in real-time, which
will add to the overall reliability of the
Bulk-Power System. We note that the
Blackout Report identified the
inadequate training of operating
personnel as a factor that was common
to some major outages that it
reviewed.269 Further, it suggests that
prior blackouts could have been
prevented if the operators had believed
that they had the responsibility and
authority to act.270
755. The Commission agrees with
NERC that this Reliability Standard
should be applicable to all transmission
operators and balancing authorities.
How local transmission and generation
control centers are incorporated into the
definition of transmission operator and
generator operator is described in the
COM Chapter of this NOPR.
756. Accordingly, the Commission
proposes to approve PER–001–0 as
mandatory and enforceable. We propose
to find that the Reliability Standard is
just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
c. Operating Personnel Training (PER–
002–0)

751. No substantive issues were
identified concerning PER–001–0.

i. NERC Proposal
757. PER–002–0 requires that
transmission operator and balancing
authority personnel are adequately
trained. Requirement R2 directs each
transmission operator and balancing

266 Reliability Standard EOP–003–0 addresses the
need to provide safeguards to shield operators from
retaliation when they declare an emergency or shed
load in accordance with previously approved
guidelines.

267 See, e.g., NYSRC, WECC/OTS, ReliabilityFirst
and NERC.
268 PER–001–0, Measure M1.
269 Blackout Report at 107.
270 Id. at 110.

ii. Staff Preliminary Assessment
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iii. Comments
752. Several commenters recommend
that the Commission accept the
proposed Reliability Standard.267

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authority to have a training program for
all operating personnel who occupy
positions that either have primary
responsibility, directly or indirectly, for
the real-time operation of the BulkPower System or who are directly
responsible for complying with the
NERC Reliability Standards. According
to NERC’s petition, the purpose of a
training program is to ensure that
operating personnel are capable of
competently performing their tasks.
Requirement R3 lists the criteria that
must be met by the training program to
attain that goal and Requirement R4
calls for operating personnel to receive
at least five days of training in
emergency operations each year using
realistic simulations of system
emergencies.
ii. Staff Preliminary Assessment
758. While PER–002–0 sets out broad
objectives that a training program must
satisfy, the Staff Preliminary
Assessment stated that it does not
specify the minimum expectations of a
training program consistent with the
roles, responsibilities and authorities of
operating and support personnel. As
such, staff explained that the nature,
objective and criteria of operator
training programs and minimum hours
of training (other than a requirement of
five days per year for realistic
simulation training) are open to
interpretation. Staff expressed concern
that the lack of specificity in this
Reliability Standard will allow training
programs to vary widely in their
implementation.
759. Further, staff stated that the
proposed Reliability Standard does not
tailor training programs according to the
needs of reliability coordinators,
balancing authorities, transmission
operators, generator operators and
operation planning and support
personnel with differing authorities,
responsibilities, roles and tasks.
Additionally, staff observed that this
Reliability Standard should also apply
to reliability coordinators, generator
operators, operations planning and
operations support staff because they
also play an important role in
maintaining Bulk-Power System
reliability.
760. Finally, the Staff Preliminary
Assessment noted that there is a widely
accepted Systematic Approach to
Training (SAT) methodology that has
been successfully used in the electric
industry as well as other industries.
According to the Staff Preliminary
Assessment, PER–002–0 should be
revised to incorporate some of the
elements of the SAT methodology.

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iii. Comments
761. NERC agrees with the Staff
Preliminary Assessment with respect to
training issues, with a few minor
clarifications. NERC states that there
must be minimum specific criteria for
training critical reliability personnel
and training must be custom designed
and delivered to be effective. NERC also
agrees with staff on the need to expand
training requirements to other persons
in addition to real-time operators.
However, NERC believes it more
important, at this point, to focus its
proposed training Reliability Standards
on those positions directly responsible
for real-time operations. NERC states
that currently work is ongoing to
develop new, substantially more robust
Reliability Standards for training that
address staff’s points.
762. EEI supports strengthening the
full range of training programs and
initiatives but believes that a one-sizefits-all approach is inappropriate. Also,
EEI states that developing strong
programs, such as those used in the
nuclear industry, may result in setting
requirements that go far beyond those
needed for many operations personnel.
EEI notes that a drafting team has begun
development of a new Reliability
Standard for training, with a possible
filing date with the Commission near
the end of 2006.
763. ISO/RTO Council notes that
many of the Requirements have illdefined terms, no measures of
compliance and lack specificity. ISO/
RTO Council argues that rather than
defining the objective of the training
program, PER–002–0 leaves an
individual entity to develop a training
program on its own. Concurring with
the Staff Preliminary Assessment,
NYSRC, NERC and ReliabilityFirst state
that PER–002–0 should specify the
minimum requirements of a training
program. Moreover, ISO/RTO Council
recommends that the PER Reliability
Standards should specifically identify
the positions that are directly
responsible for complying with the
proposed Reliability Standard.
764. NERC and WECC/OTS support
the use of the SAT concept, which
would customize training to the job
requirements of each position. Although
WECC/OTS endorses the five-day
training requirement, it asserts that
specifying a minimum number of
training hours devoted to a certain task
or establishing a mandatory curriculum
within the Reliability Standard is
inconsistent with the SAT concept. It
argues that the training needs of one
transmission operator may be quite
different from another due to size,

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impact on the Interconnection, and
experience and skill of its operating
personnel. ISO/RTO Council generally
supports a performance-based approach
to training and metrics.
765. Although several commenters
support the Staff Preliminary
Assessment,271 National Grid maintains
that some of staff’s comments on the
PER Reliability Standards are overly
prescriptive and appear to be mandating
various training tools, such as
simulation training and SAT, without
assessing the cost effectiveness of such
measures. It contends that the PER
Reliability Standards should focus on
performance measures without being
overly prescriptive.
766. Along with NERC, WECC/OTS
supports expanding the applicability of
training programs. WECC/OTS further
recommends that training requirements
should apply to all personnel with the
ability to affect real-time operations of
the Bulk-Power System. However, it
believes that the training programs
should focus on positions directly
responsible for real-time operations at
this point. In contrast, National Grid
expresses concern regarding the Staff
Preliminary Assessment’s suggestion to
expand training to other functions with
responsibilities for Bulk-Power System
reliability. Specifically, it argues that
there is an implication that all
employees listed within the categories
identified by staff would be required to
receive training even if some have no
responsibility for grid reliability. It
suggests that the staff’s comments in
this area should be taken by NERC as a
cue to explore expanding training to
necessary areas without requiring all
employees within a function or category
to receive training.
767. WECC/OTS notes that a full scale
simulator can be an effective tool in
operator training, but cautions against a
requirement that all operating entities
employ a full-scale simulator, stating
that emergency training can be
effectively provided through other
means, i.e., drills or computer models.
With regard to the EPAct 2005 provision
for training guidelines for non-nuclear
electric energy industry personnel, it
maintains that the provision should not
apply to the ERO with the exception of
the operation function. Nonetheless,
WECC/OTS argues that training in other
areas cited in EPAct 2005 should be
covered in a specific course tailored to
the function’s effect on the real-time
reliability of the Bulk-Power System. It
argues that requirements for initial
certification, assessment and
recertification identified in EPAct 2005

should be separated from the
requirements of system operators.
768. NYSRC recommends that the
Commission conditionally approve
PER–002–0, while WECC/OTS supports
approval of the proposed Reliability
Standard with the understanding that
NERC is currently developing a new
Reliability Standard to replace PER–
002–0 with an emphasis on the SAT
process.
iv. Commission Proposal
769. The Commission proposes to
approve PER–002–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
770. Inadequate operator training has
been identified as a common factor
among past major system outages.272 In
the context of the task force
investigation of the August 2003
blackout, the Blackout Report stated that
some reliability coordinators and
balancing authority operators did not
receive adequate training in recognizing
and responding to system
emergencies.273 The ‘‘deficiency in
training contributed to the lack of
situational awareness and failure to
declare an emergency while operator
intervention was still possible (before
events began to occur at a speed beyond
human control.)’’ 274
771. PER–002–0 requires that each
transmission operator and balancing
authority shall be staffed with
adequately trained personnel and
directs the transmission operator and
balancing authority to have training
programs for all their operating
personnel who occupy positions that
either have primary responsibility,
directly or indirectly, for the real-time
operation of the Bulk-Power System or
who are directly responsible for
complying with the Reliability
Standards. Transmission operators and
balancing authorities are not the only
entities that have operating personnel in
positions that directly impact the
reliable operation of the Bulk-Power
System or must comply with the
Reliability Standards. Reliability
coordinators, generator operators,
operations planning and operations
support staff also potentially impact the
reliable operation of the Bulk-Power
System, yet these entities are not
required to participate in mandatory
training programs. The Commission
agrees with NERC, WECC/OTS and
National Grid and supports the
272 Blackout
273 Id.

271 NERC,

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Report at 107.
at 157.

274 Id.

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expanding training programs to other
personnel with the ability to affect realtime operations of the Bulk-Power
System. The Commission proposes that
such expansion be based on the role of
the entity rather than its size. Further,
we note that NERC has stated that it has
asked its Reliability Standards drafting
team to prepare a request for a new
project to expand the scope of the
training requirements to other positions
essential to reliability of the Bulk-Power
System.
772. After considering the comments
of NERC and National Grid that the
training programs should focus on
positions directly responsible for realtime operations at this point in time,
and in recognition of the need to give
first priority to real-time operations, the
Commission proposes a modification of
PER–002–0 to include real-time
operations personnel from reliability
coordinators, generator operators,
operations planning and operations
support staff in training programs with
a time phased effective date. The
phasing of the effective date would
acknowledge the priority of training
each group. This prioritization is also
supported by WECC/OTS which
cautions that limited training resources
may be diverted from system operators
to other personnel that can effect
reliable operation at the expense of
those responsible for real-time
operations.
773. In order to maintain an adequate
level of reliability, the Commission
proposes to require NERC to modify
PER–002–0 in the future or to develop
a new training Reliability Standard for
all personnel who may directly impact
the reliable operation of the Bulk-Power
System or for all personnel who have
responsibility for compliance with the
Reliability Standards. These personnel
include operations planning and
operations support staff. We disagree
with the comments of EEI and believe
that this does not imply a one-size-fitsall approach. Rather, this course of
action ensures the creation of training
programs that are structured and
tailored to the different functions and
needs of the personnel involved.
774. A review of operator
demographics reveals that a large
percentage of electrical operators will
retire over the next five years. As these
older and more experienced operators
retire, the need for structured,
comprehensive and effective training
programs tailored to the needs of the
functions and individuals become even
more crucial, and will need to be
developed and implemented for
incoming operators who will not have
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training, mentoring and knowledge
transfer from experienced operators.
Requirement R3 sets out broad
objectives that a training program must
satisfy, yet it does not specify the
minimum expectations of an effective
training program. In its comments,
NERC agrees with the Staff Preliminary
Assessment that PER–002–0 must have
minimum expectations and specific
criteria for training critical reliability
personnel. The Commission concurs
with NERC’s comments, calling for
measurable requirements regarding
objectives, content, minimum hours of
training and types of training in the
proposed Reliability Standard. The
Commission proposes that NERC
modify the Reliability Standard to
include minimum training requirements
related to objectives, program content,
minimum hours of training and types of
training with specific performance
metrics to gauge the effectiveness of the
training program.
775. Although EEI cautions against
using the nuclear industry training
program as a model, we do not believe
that the use of an SAT method would
set requirements that go beyond those
needed for many operating personnel.
We agree with WECC/OTS that training
based on SAT is a proven approach to
identify the tasks and associated skills
and knowledge necessary to accomplish
those tasks, determine the competency
level of each operator to carry out those
tasks, determine the competency gaps,
then design, implement and evaluate a
training plan to address each operator’s
competency gaps.
776. CenterPoint and National Grid
caution against being overly prescriptive
and propose that the Commission focus
on desired outcomes. ISO/RTO Council
stated that there is no definition for
‘‘adequately trained operating
personnel’’ and suggested the adoption
of performance metrics to ensure that
training results in competent operating
personnel. These are distinct from
measures used to ensure compliance
with the requirements. The Commission
strongly supports the adoption of
performance metrics to ensure that
training results in competent operating
personnel. However, such performance
metrics are not a substitute for an SAT
developed training program. The
Commission proposes to require that
NERC modify PER–002–0 to include
performance metrics associated with the
effectiveness of the training program.
777. Effective training programs must
be structured and address competency
gaps of operating personnel. WECC/OTS
states that SAT-based training plans
tailor to the needs of not only various
job functions, but also to individual

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operator competency gaps within those
functions. WECC/OTS and NERC
support this approach in identifying the
tasks and associated skills and
knowledge necessary to accomplish the
specific tasks of each operator. In
addition, they support implementing
and evaluating a unique training plan to
address each operator’s competency
gap. NERC stated that the
implementation of minimum training
requirements, as well as an SAT
methodology, is essential to ensuring
system operator competencies. NERC
claims that a new Reliability Standard is
under development which will address
the above concerns. The Commission
proposes that NERC explore the SAT
methodology in its efforts to establish
training plans tailored to the needs of
various job functions and individuals.
778. Requirement R4 of the Reliability
Standard requires training in emergency
operations using realistic simulations of
system emergencies. Several entities
currently use full scale operator training
simulators for this purpose with
scenarios derived from actual system
disturbances supplemented with drills
to deal with communications during
emergencies. WECC/OTS notes that the
use of such a simulator can be an
effective tool in operator training
programs, but cautions against making
this a requirement for all operating
entities. The Commission notes that
there are various options available for
providing operator training simulator
capability, including contracting for this
service from others who have developed
the capability. The Commission solicits
comments on the benefits and
appropriateness of required ‘‘hands-on’’
training using simulators in dealing
with system emergencies as identified
in the training related recommendations
made in studies of major outages.275
779. The Commission proposes that
this Reliability Standard be Applicable
to transmission operators, balancing
authorities, reliability coordinators,
generator operators, and operations
planning and operations support staffs
that have a direct impact on the reliable
operation of the Bulk-Power System.
How local transmission and generation
control centers are incorporated into the
definition of transmission operator and
generator operator is described in the
COM Chapter. The extent of the training
shall take into account the need to
assure real time operators do not suffer
because of the training needs of non-real
time staff.
780. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
275 Id.

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Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PER–002–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PER–002–0 that: (1) Identifies the
expectations of the training for each job
function; (2) develops training programs
tailored to each job function with
consideration of the individual training
needs of the personnel; (3) expands the
Applicability to include reliability
coordinators, generator operators, and
operations planning and operations
support staff with a direct impact on the
reliable operation of the Bulk-Power
System; (4) uses the SAT methodology
in its development of new training
programs; and (5) includes performance
metrics associated with the effectiveness
of the training program.
d. Operating Personnel Credentials
(PER–003–0)
i. NERC Proposal
781. PER–003–0 requires transmission
operators, balancing authorities and
reliability coordinators to staff all
operating positions that have a primary
responsibility for real-time operations or
are directly responsible for complying
with the Reliability Standards with
NERC-certified staff. NERC grants
certification to operating personnel
through a separate program documented
in the NERC System Operator
Certification Manual and administered
by an independent Personnel
Certification Governance Committee.
ii. Staff Preliminary Assessment

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782. In its Staff Preliminary
Assessment, staff stated that this
Reliability Standard does not specify the
minimum competencies that operating
personnel must demonstrate to meet the
certification requirements.276 Although
NERC’s System Operator Certification
Program Manual outlines the
requirements for certification, the
manual is not a part of the proposed
Reliability Standard. Therefore, staff
contended that the Manual is not
enforceable.277
276 Staff

Preliminary Assessment at 89–90.
American Electric Reliability Council’s
Application for Certification as the Electric
Reliability Organization, Rules of Procedure of the
Electric Reliability Organization, System Operator
Certification Program Manual, Appendix 6 available
at ftp://www.nerc.com/pub/sys/all_updl/ero/
application/ERO-Application-Complete.pdf.
277 North

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783. Moreover, staff noted that
generator operators, who have
responsibility for the real-time operation
of the Bulk-Power System and are
directly responsible for complying with
NERC Reliability Standards, do not
require NERC-certification under this
Reliability Standard.
iii. Comments
784. NERC does not agree with the
Staff Preliminary Assessment’s view
that the NERC System Operator
Certification Program Manual should be
included in the Reliability Standard to
be enforceable. It states that this is a
procedural document and the
Certification Program is managed by an
independent Personnel Certification
Governance Committee as required by
the standards of the National
Organization for Competency Assurance
and employment law.
785. WECC/OTS and NYSRC join
with comments of the Staff Preliminary
Assessment in observing that the
Applicability and Requirements
sections of PER–003–0 potentially
weaken the enforcement of this
Reliability Standard. While WECC/OTS
encourages Commission approval of
PER–003–0 with the understanding that
NERC or another interested party will
submit a Standard Authorization
Request to more specifically define
which functions should be performed
by certified personnel, NYSRC
recommends conditional approval of
PER–003–0. Although the ISO/RTO
Council does not address staff’s
comment that the NERC Manual is not
enforceable, it agrees that the proposed
Reliability Standard should contain
minimum Certification Requirements. It
also implies that the NERC System
Operator Certification Program Manual
contains the needed level of
requirements and measurability. In
contrast, WECC/OTS opposes including
the specific competencies operating
personnel must demonstrate to meet the
certification requirements. It states that
these details are retained with the
certification program governance body.
786. ReliabilityFirst disagrees with
the Staff Preliminary Assessment’s
comments regarding PER–003–0. It
asserts that personnel are obligated to
follow the appropriate NERC process to
become certified. It argues that PER–
003–0 should make reference to this as
a stand-alone manual that could be
adjusted and maintained without
affecting the current Reliability
Standard.
iv. Commission Proposal
787. The Commission proposes to
approve PER–003–0 as mandatory and

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64843

enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
788. PER–003–0 requires applicable
entities to staff real-time operation
positions with NERC-certified
personnel. The Commission interprets
this to include real-time operating
positions in a transmission operations
control center that performs switching
operations via SCADA for the BulkPower System.
789. Some commenters agree with
staff that PER–003–0 should contain
minimum certification requirements,
while others do not. The Commission
acknowledges the commenter’s
concerns and the convenience of
maintaining a procedural document that
is separate from the Reliability Standard
so that it can be modified without
requiring a revision to the entire
Reliability Standard. Nevertheless, the
Commission believes that the minimum
competencies that must be
demonstrated to become a certified
operator and the minimum
requirements to remain certified should
be included in PER–003–0. To address
commenter’s concerns, we propose that
the ERO modify PER–003–0 to identify
the minimum competencies operating
personnel must demonstrate to be
certified, but not include the entire
Certification Program Manual.
790. Additionally, we note that
generator operators who have
responsibility for real-time operation of
the Bulk-Power System and who are
directly responsible for complying with
the Reliability Standards are not
designated in the Applicability section
of PER–003–0, and therefore, do not
require NERC-certification. We agree
with the concerns articulated in the
Staff Preliminary Assessment and we
believe that this omission has the
potential to impact the reliable
operation of the Bulk-Power System.
Therefore, the Commission proposes the
modification of PER–003–0 to include
generator operators as applicable
entities.
791. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PER–003–
0 as mandatory and enforceable. In
addition, we propose to direct NERC to
modify the Reliability Standard to
address the Commission’s concerns. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our

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regulations, the Commission proposes to
direct NERC to submit a modification to
PER–003–0 that: (1) Expands the
Applicability to include generator
operators; (2) specifies the minimum
competencies that must be
demonstrated to become and remain a
certified operator; and (3) identifies the
minimum competencies operating
personnel must demonstrate to be
certified (but not include the
Certification Program Manual).
e. Reliability Coordination—Staffing
(PER–004–0)
i. NERC Proposal
792. PER–004–0 ensures that
reliability coordinator personnel are
adequately trained, NERC-certified, and
staffed 24 hours a day, seven days a
week with properly trained and certified
individuals. Further, reliability
coordinator operating personnel must
have a comprehensive understanding of
the area of the Bulk-Power System over
which they are responsible, including
familiarity with transmission operators,
generator operators and balancing
authorities, as well as their operating
practices and procedures, equipment
capabilities and restrictions, system
operating limits and interconnection
reliability operating limits.278 In
addition the reliability coordinator must
complete a minimum of five days per
year of emergency operations training in
addition to the training required to
maintain qualified operating personnel.
793. NERC indicates that it will
modify this proposed Reliability
Standard to address the lack of
Measures and Levels of NonCompliance and resubmit the proposal
for Commission approval in November
2006.
ii. Staff Preliminary Assessment
794. The Staff Preliminary
Assessment noted that there was no
formal training program requirement for
reliability coordinators similar to the
program required for transmission
operators and balancing authority
personnel under PER–002–0.

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iii. Comments
795. ReliabilityFirst notes that PER–
004–0 does require reliability
coordinators to be NERC-certified and to
complete required training. WECC/OTS
states that the NERC System Personnel
Training Reliability Standard, which is
278 A comprehensive understanding of a
reliability coordinator’s ‘‘area’’ includes: Familiarity
with transmission operators, generator operators
and balancing authorities, as well as their operating
practices and procedures, equipment capabilities
and restrictions, system operating limits and
interconnection reliability operating limits.

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under development, includes reliability
coordinators in the applicability section.
796. ReliabilityFirst, NYSRC and ISO/
RTO all note the Reliability Standard’s
lack of Measures and Levels of NonCompliance.
iv. Commission Proposal
797. The Commission proposes to
approve PER–004–0 as mandatory and
enforceable. In addition, we propose
directing that NERC develop
modifications to the Reliability
Standard, as discussed below.
798. A reliability coordinator is the
entity with the highest level of authority
that is responsible for the reliable
operation of the Bulk-Power System, has
a ‘‘wide area view,’’ and has the
operating tools, processes and
procedures, including authority to
prevent or mitigate emergency operating
situations in both next-day analysis and
real-time operations.279 Most of the
Requirements for PER–004–0 address
training issues pertaining to reliability
coordinators, yet there is no
requirement for a formal training
program for reliability coordinators that
is similar to the program required for
transmission operators under PER–002–
0. We believe that the addition of formal
training requirements for reliability
coordinators will help to ensure
adequate training and competency for
an entity that plays a critical role in
ensuring the reliability of the
interconnected grid. To ensure that the
training requirements for reliability
coordinators are comprehensive, we
propose that the ERO either modify
PER–006–0 to include the same quality
and clarity as the training requirements
for other operating personnel as set forth
in PER–002–0 or, alternatively, given
the high priority work that the ERO
must accomplish it may want to
consider including the reliability
coordinator as an applicable entity in
PER–002–0. Similarly, we propose that
the ERO either modify PER–006–0 to
address personnel credentials for
reliability coordinators in a similar
manner as for other operating personnel
in PER–003–0 or, alternatively, it may
address this concern by including
reliability coordinators as an applicable
entity in PER–006–0.
799. We agree with commenters that
Measures and Levels of NonCompliance should be added to the
proposed Reliability Standard,
including Measures to address staffing
requirements and the minimum five
days of emergency training.
800. While the Commission has
identified a number of concerns with

regard to PER–003–0, this proposed
Reliability Standard serves an important
purpose of ensuring that reliability
coordinator personnel are adequately
trained. Further, NERC should provide
Measures and Levels of NonCompliance for this proposed Reliability
Standard. Nonetheless, the
Requirements set forth in PER–003–0
are sufficiently clear and objective to
provide guidance for compliance.
801. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PER–004–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PER–004–0 that: (1) Includes formal
training requirements for reliability
coordinators similar to those addressed
under the personnel training Reliability
Standard PER–002–0; (2) includes
requirements pertaining to personnel
credentials for reliability coordinators
similar to those in PER–003–0; and (3)
includes Levels of Non-Compliance and
Measures that address staffing
requirements and the requirement for
five days of emergency training.
10. PRC: Protection and Control
a. Overview
802. Protection and Control (PRC)
systems on Bulk-Power System
elements are an integral part of reliable
grid operation. Protection systems are
designed to detect and isolate a faulted
element from the system, thereby
limiting the severity and spread of
system disturbances and preventing
possible damage to protected elements.
SOLs and IROLs are only valid when
they recognize the function, settings and
limitations of the protection system.
One of the common factors among the
major outages from 1965 to 2003 was
the lack of coordination of system
protection.280
803. The PRC Reliability Standards
apply to transmission operators,
transmission owners, generator
operators, generator owners,
distribution providers and regional
reliability organizations and cover a
wide range of topics related to the
protection and control of power
systems.281 NERC has recognized that
280 Blackout

Report at 107.
addressed under the PRC Reliability
Standards include: system protection coordination,
281 Topics

279 See

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the Reliability Standards do not form a
complete set of PRC Reliability
Standards to meet the goal of
reliability.282
804. Generally, the proposed
Reliability Standards in the PRC group
raise issues related to Measures, Levels
of Non-compliance, and Requirements.
The regional reliability organization is
the compliance monitor for twelve of
the PRC Reliability Standards 283 and
the applicable entity for seven of
them.284
b. System Protection Coordination
(PRC–001–0)
i. NERC Proposal
805. Proposed Reliability Standard
PRC–001–0 ensures that protection
systems are coordinated among
operating entities by requiring
transmission operators and generator
operators to notify appropriate entities
of relay or equipment failures that could
impact system reliability. In addition,
these entities must coordinate with
appropriate entities when new
protection systems are installed or when
existing protection systems are
modified.
ii. Staff Preliminary Assessment

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806. The Staff Preliminary
Assessment pointed out that
Requirement R2 of PRC–001–0 instructs
transmission operators or generator
operators to take corrective action as
soon as possible where a protective
relay or equipment failure reduces
system reliability. However, PRC–001–0
does not designate a maximum time
period for corrective control actions.
This is inconsistent with the
requirement that system operators readjust the system within 30 minutes for
contingencies under the proposed IRO
and TOP Reliability Standards. Staff
also noted that the lack of Measures and
Levels of Non-Compliance in this
disturbance monitoring, under-frequency load
shedding (UFLS), special protection systems,
under-voltage load shedding (UVLS) and their
assessments, database, event and mis-operation
analysis, maintenance and testing requirements and
performance evaluation.
282 See NERC Planning Standards Phase III-IV,
available at http://www.nerc.com/∼filez/standards/
Phase-III–IV.html.
283 The regional reliability organization is
assigned compliance monitoring responsibility
under the following Reliability Standards in the
PRC group: PRC–004–1; PRC–005–1; PRC–007–0;
PRC–008–0; PRC–009–0; PRC–010–0; PRC–011–0;
PRC–015–0; PRC–016–0; PRC–017–0; PRC–018–1;
PRC–021–1; and PRC–22–1.
284 The regional reliability organization is listed
as the applicability entity under the following
Reliability Standards in the PRC group: PRC–002–
0; PRC–003–1; PRC–006–0; PRC–012–0; PRC–013–
0; PRC–014–0; and PRC–020–1.

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Reliability Standard may hinder
consistent and effective enforcement.
iii. Comments
807. NERC agrees with staff that PRC–
001–0 requires modification and
requests that the Commission
conditionally approve it. NERC reasons
that even if a generator operator fails to
tend to a protective relay failure, other
proposed Reliability Standards still
require the transmission operator and
reliability coordinator to ensure reliable
operation of the grid by mitigating SOL
and IROL violations as soon as possible.
In addition, NERC indicates that it will
modify this Reliability Standard to
include missing Measures and Levels of
Non-Compliance and resubmit it for
Commission approval in November
2006.
808. CPUC argues that ‘‘action
adequate to bring the system into
balance’’ may be ambiguous, i.e., a more
effective action taken in 35 minutes may
be preferable to a less effective action
taken in 28 minutes in an attempt to
follow the 30-minute time limit
specified under the IRO and TOP
Reliability Standards. It also stated that
the Staff Preliminary Assessment’s
concern apparently relates to the August
2003 Blackout, where operators failed to
take effective action in the very short
time frame required to prevent
cascading outages throughout the
region. CPUC questions the extent to
which a rigid 30-minute maximum time
limit would have prevented much of the
system dysfunction that occurred in
August 2003.
809. National Grid suggests that
requiring a maximum time period for
corrective actions where a protective
relay or equipment failure reduces
reliability inappropriately mixes
protection design engineering issues
with operational issues. National Grid
asserts that the proposed Reliability
Standard addresses design engineering
and specifying a maximum time period
for corrective actions to respond to
protective equipment failures would be
inappropriate. Further, CenterPoint
states that the amount of time required
to diagnose and correct different types
of failures varies. It explains that
investigating and correcting relay
failures is a fundamentally different
exercise from that of real-time operators
taking corrective actions in response to
operating contingencies that may occur.
810. ReliabilityFirst agrees that a
failed protection system element must
be replaced as soon as possible, but
agrees with staff that PRC–001–0 should
clearly state that system performance
requirements must continue to be met
when the affected protection system

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element has failed or is out of service.
Repair or replacement of the failed
protection element or an alternate
corrective solution, such as operator
control action, must be implemented to
satisfy performance requirements.
ReliabilityFirst concludes that a specific
time for repairing the failed protection
system element is not necessary if
performance requirements must be
maintained.
iv. Commission Proposal
811. The Commission proposes to
approve PRC–001–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard as discussed
below.
812. We recognize that protection and
control systems are integral part of
reliable grid operation and agree that
protection systems affect the validity of
IROLs. We further note that if a nonredundant protection system for a
critical element fails and no corrective
control action is taken, the system could
be subject to the risk of cascading failure
if a critical contingency subsequently
occurred.
813. The Commission emphasizes the
importance of immediately informing
transmission operators and generator
operators of any protection failure that
may affect SOLs and IROLs so that they
can take corrective control action to
maintain reliable system operations. We
further note that PRC–001–0 or other
relevant PRC Reliability Standards do
not contain such a Requirement.
814. PRC–001–0 should designate a
maximum time limit for corrective
control action where the failure of a
protection system element has reduced
system reliability and undermined
performance requirements. The
Commission commends NERC’s
initiative in attempting to address and
clarify this issue in PRC–001–0.
However, we do not agree with NERC
that even if a generator operator fails to
tend to a protective relay failure, other
proposed Reliability Standards still
require the transmission operator and
reliability coordinator to ensure the
reliable operation of the grid by
mitigating SOL and IROL violations as
soon as possible, i.e., respecting
performance requirements. We believe
that the Reliability Standards on
mitigating IROL violations are not
specific enough and system operators or
field protection and control personnel
would not be alerted about failures of
relays and protection systems on critical
elements. Therefore, in addition to
clarifying the ambiguity in future
revision, we propose to require NERC to
include a requirement that the

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appropriate transmission operators or
generator operators should be notified
immediately upon detection of failures
on relays or protection systems on BulkPower System elements so that they can
maintain system reliability requirements
by taking corrective actions in the same
manner used to mitigate IROL
violations.
815. The Commission does not agree
with National Grid’s comment that
staff’s concern inappropriately mixes
protection design engineering issues
with operational issues. Design
engineering refers to protection system
schemes with protective elements, such
as relays. Furthermore, the applicable
entities for design engineering would
include field protection and control
personnel who are responsible for
carrying out the inspection, replacement
and repair of damaged protection
system elements. PRC–001–0 requires
transmission operators or generator
operators to carry out corrective actions
because this Reliability Standard
addresses system performance
requirements. We believe that the Staff
Preliminary Assessment correctly
advocated the establishment of a
maximum time period for corrective
control actions when a protective relay
or equipment failure reduces reliability,
i.e., performance requirements that are
consistent with mitigating IROL
violations.
816. The Commission believes that
CenterPoint also misinterpreted the
Staff Preliminary Assessment’s concern.
The Staff Preliminary Assessment
advises the addition of a requirement
that transmission operators carry out
corrective control actions to return the
system to a secure state, i.e., respecting
system performance requirements, by
recognizing the reduction in IROL due
to a failed relay or protection system
elements in no longer than 30 minutes.
It is generally understood that the
corrective actions stated in this
Reliability Standard do not include
actions requiring the field protection
and control personnel to respond and
repair faulty relays or failed protection
system elements as this type of repair
would normally take hours, if not days.
817. The Commission does not share
CPUC’s view that the Staff Preliminary
Assessment is advocating a rigid 30minute requirement to re-adjust the
system or fix or replace failed protection
system elements. Since failures of relays
or protection system elements would
expose the Bulk-Power System to
cascading outages through a possible
failure to respect performance
requirements, we believe that
transmission operators and generator
operators must take corrective control

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actions in the same manner used to
mitigate IROL violations as stipulated in
relevant IRO and TOP Reliability
Standards, as soon as possible but no
more than 30 minutes.
818. The Commission agrees with
ReliabilityFirst that protection system
elements must be replaced as soon as
possible, and PRC–001–0 should clearly
state that system performance
requirements must continue to be met
when the affected protection system
element is out of service.
819. Although the Commission has
identified concerns regarding PRC–001–
0’s lack of a maximum interval for
corrective control action when a
protection system element has failed
and reduced reliability, i.e., system
performance requirements, we believe
that the proposed Reliability Standard
provides a good base and is integral to
ensuring that system protection is
coordinated among operating entities.
The Commission also believes that it is
important for NERC to provide
Measures and Levels of NonCompliance for the proposed Reliability
Standard. However, the Requirements
set forth in PRC–001–0 are sufficiently
clear and objective to provide guidance
for compliance.
820. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PRC–001–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PRC–001–0 that: (1) Includes
Measures and Levels of NonCompliance; (2) includes a requirement
that relevant transmission operators and
generator operators must be informed
immediately upon the detection of
failures in relays or protection system
elements on the Bulk-Power System that
would threaten reliable operation, so
that these entities can carry out the
appropriate corrective control actions
consistent with those used in mitigating
IROL violations; and (3) clarifies that,
after being informed of failures in relays
or protection system elements on the
Bulk-Power System, transmission
operators or generator operators shall
carry out corrective control actions, i.e.,
returning the system to a stable state
that respects system requirements as
soon as possible and no longer than 30
minutes.

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c. Define Regional Disturbance
Monitoring and Requirements (PRC–
002–1)
i. NERC Proposal
821. Proposed Reliability Standard
PRC–002–1 ensures that each regional
reliability organization establishes
requirements to install Disturbance
Monitoring Equipment (DME) and
report disturbance data to facilitate
analyses of events and verify system
models.
822. NERC’s August 28, 2006
Supplemental Filing, as corrected on
September 12, 2006, includes a revised
version of PRC–002–0, designated as
PRC–002–1. This revised Reliability
Standard still applies to regional
reliability organizations. Both of the
original Requirements have been
substantially revised.285 Requirement
R1 from version 0 was substantially
revised to require the regional reliability
organization to establish certain
installation requirements for sequence
of event recording. Requirement R2
from version 0 was modified to replace
the regional reliability organization with
transmission owners and generator
owners and designated as Requirement
R5 in version 1. The revised PRC–002–
1 includes four new Requirements:
Requirement R2 (installation
requirement for fault recording),
Requirement R3 (installation
requirement for dynamic disturbance
recording), Requirement R4 (disturbance
data reporting requirements), and
Requirement R6 (regional reliability
organization requirement to periodically
review, update, and approve regional
requirements for disturbance monitoring
and reporting). In PRC–002–1, two new
Measures for Requirements R4 and R6
have been added and compliance was
modified to include new Requirements.
ii. Staff Preliminary Assessment
823. The Staff Preliminary
Assessment noted that PRC–002–0 is a
fill-in-the-blank standard and identifies
the regional reliability organization as
the sole applicable entity, and PRC–
002–1 does as well.
iii. Comments
824. A number of commenters
discussed how the Commission should
address PRC–002–1 and other
Reliability Standards in the PRC group
that are ‘‘fill-in-the-blank’’ standards.286
285 We note that PRC–002–0 has been revised and
separated into two Reliability Standards, PRC–002–
1 (Define Regional Disturbance Monitoring and
Reporting Requirements) and PRC–018–1
(Disturbance Monitoring Equipment Installation
and Data Reporting).
286 CPUC, FRCC, National Grid, NPCC, NYSRC,
ReliabilityFirst, Southern and TANC. Their

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CPUC and National Grid share the Staff
Preliminary Assessment’s concern that
certain ‘‘fill-in-the-blank’’ Reliability
Standards are not written in a manner
allowing enforcement against users,
owners and operators of the Bulk-Power
System. They point out that some of
these Reliability Standards must be
‘‘substantively regional’’ due to their
unique characteristics and the physical
realities of various regional transmission
grids, citing examples such as underfrequency load shedding (UFLS) and
under-voltage load shedding (UVLS)
schemes, which are necessarily
regionally unique. Further, they state
that some are ‘‘procedurally regional’’
because they must be implemented by a
regional body.287 National Grid urges
the Commission and NERC that any
revision of these Reliability Standards
must adequately address these
substantive and procedural concerns.
825. Southern indicates that the
industry and NERC are currently
considering revisions to the ‘‘fill-in-theblank’’ standards. It states that revision
would require a significant amount of
time and coordination within the
industry. Mandatory Reliability
Standards must enhance and not detract
from reliability.
826. TANC advises the Commission to
approve these ‘‘fill-in-the-blank’’
Reliability Standards on an interim
basis until the applicable Regional
Entities and NERC have conducted the
appropriate approval procedure and are
able to re-submit these Reliability
Standards in final form to the
Commission for its approval.

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iv. Commission Proposal
827. Because regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
002–1 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with PRC–002–1 should continue on its
present basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
comments also apply to PRC–003–1, PRC–006–0,
PRC–012–0, PRC–013–0; PRC–014–0 and PRC–020–
1.
287 An example of this is PRC–013–0, which
requires the establishment of a regional database for
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d. Regional Procedure for Analysis of
Misoperations of Transmission and
Generation Protection Systems (PRC–
003–1)
i. NERC Proposal
828. PRC–003–1 ensures that all
transmission and generation protection
system misoperations are analyzed, and
corrective action plans are developed.
Misoperations occur when a protection
system operates when it should not or
does not operate when it should have.
This Reliability Standard requires the
regional reliability organization to
develop a procedure to monitor and
review misoperations of protection
systems as well as the development and
documentation of corrective actions. As
discussed in PRC–002–0, this is one of
the proposed Reliability Standards
referred to as a ‘‘fill-in-the-blank’’
Reliability Standard.
ii. Staff Preliminary Assessment
829. Similar to its discussion of PRC–
002–0, staff noted that this Reliability
Standard designates a regional
reliability organization as the sole
applicable entity. Staff was concerned
about the feasibility of a regional
reliability organization serving as the
applicable entity and the enforceability
of the proposed Reliability Standard in
the mandatory Reliability Standards
structure.
iii. Comments
830. A number of commenters
discussed how the Commission should
address PRC–003 and other Reliability
Standards in the PRC group that are
‘‘fill-in-the-blank’’ standards. In
addition, ISO/RTO Council states that
PRC–003–1 needs to better define the
contents of the procedures in the
Requirements and that the proposed
Reliability Standard is unclear about
how it may be effectively measured.
iv. Commission Proposal
831. The Commission does not share
ISO/RTO Council’s view that a better
definition of the contents of the regional
reliability organization’s procedure is
required. We refer to the list of elements
that are included in Requirements R1.1
to R1.5 to address transmission system
protection misoperations. In addition,
we note that PRC–003–1 contains two
Measures requiring these procedures to
be available and submitted on a timely
basis upon request.
832. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
003–1 satisfies the statutory requirement
that a proposed Reliability Standard be

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‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with PRC–003–1 should continue on its
present basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
e. Analysis and Reporting of
Transmission Protection System
Misoperations (PRC–004–1)
i. NERC Proposal
833. Proposed Reliability Standard
PRC–004–1 ensures that all
transmission and generation protection
system misoperations affecting the
reliability of the Bulk-Power System are
analyzed and mitigated by requiring
transmission owners, generator owners
and distribution providers that own a
transmission protection system to
analyze and document protection
system misoperations. These entities
must also develop corrective action
plans in accordance with the regional
reliability organization’s procedures.
ii. Staff Preliminary Assessment
834. No substantive issues were
identified regarding PRC–004–1.
iii. Comments
835. MEAG states that, if a
distribution provider owns a
transmission protection system, the
distribution provider is also a
transmission owner according to
NERC’s glossary definition. MEAG
comments that it is unnecessary,
overbroad and contrary to FPA section
215 to include distribution providers in
any of the proposed PRC Reliability
Standards when the term ‘‘transmission
owner’’ is sufficient to cover the scope
of entities that own transmission
protection systems.
836. ISO/RTO Council comments that
PRC–004–1 should clarify the definition
of what the procedures must contain
and how PRC–004–1 can be effectively
measured.
iv. Commission Proposal
837. We disagree with the ISO/RTO
Council that the Requirements and
Measures of the proposed Reliability
Standard are unclear. Requirement R1
requires the owners of transmission
protection systems to analyze all
protection system misoperations, take
corrective actions and provide the
associated analysis documents with
corrective action plans to NERC. Further
PRC–004–1 contains Measures that

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these owners have evidence that they
analyzed protection system
misoperations and took corrective
actions, with all associated
documentation provided.
838. The applicability section of PRC–
004–1 provides that, inter alia, a
‘‘Distribution Provider that owns a
transmission Protection System’’ must
comply with this Reliability Standard.
This applicability provision makes clear
that the Reliability Standard applies
only to a subset of distribution
providers. We believe that this approach
is appropriate. With regard to MEAG’s
concern, the Commission disagrees with
MEAG that a distribution provider by
virtue of owning transmission
protection equipment becomes a
transmission owner, which would then
be subject to all of the Reliability
Standards applicable to a transmission
owner.
839. Reliability Standard PRC–004–1
serves an important purpose in ensuring
that transmission and generation
protection system misoperations
affecting the reliability of the BulkPower System are analyzed and
mitigated. For the reasons discussed
above, the Commission believes that
Reliability Standard PRC–004–1 is just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest; and proposes to approve it as
mandatory and enforceable.
f. Transmission Protection System
Maintenance and Testing (PRC–005–1)
i. NERC Proposal
840. Proposed Reliability Standard
PRC–005–1 ensures that all
transmission and generation protection
systems affecting the reliability of the
Bulk-Power System are maintained and
tested by requiring the transmission
owners, distribution providers, and
generator owners to develop, document,
and implement a protection system
maintenance program that may be
reviewed by the regional reliability
organization.

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ii. Staff Preliminary Assessment
841. The Staff Preliminary
Assessment stated that protection
systems must be maintained and tested
at regular intervals to ensure that they
will operate as intended when called
upon and that maintenance intervals
vary depending on the type and nature
of the protection system, as well as the
reliability impact of a potential failure
of that system. Staff identified several
Reliability Standards in the PRC group
addressing the maintenance and testing
of different protection systems that are
technically deficient because they do

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not specify the criteria to determine the
appropriate maintenance intervals, and
they do not specify maximum allowable
maintenance intervals for the
protections systems.288
842. Staff cited PRC–006–0 as good
example of a Reliability Standard that
requires periodic assessments of the
effectiveness of regional UFLS programs
at least once every five years regardless
of the circumstance.
iii. Comments
843. NERC states that it welcomes
discussion and debate on the proper
study and maintenance intervals for
regular and special protection systems.
It will consider these comments in the
re-authorization of these Reliability
Standards or the development of future
Reliability Standards. Within its
existing scope, the NERC System
Protection and Controls Task Force will
examine all PRC Reliability Standards
for consistency and technical
completeness. It will then propose any
appropriate modifications through the
standards process.
844. ISO/RTO Council echoes the
concerns of the Staff Preliminary
Assessment that the proposed
Reliability Standard must define the
missing maintenance intervals.
845. ReliabilityFirst contends that the
purpose of PRC–005–1 does not call for
specific justification for allowable
maintenance intervals, it calls for
intervals only. However, it urges NERC
to develop maximum allowable
intervals based on reliability-centered
study results developed by the regions
and companies therein.
iv. Commission Proposal
846. The Commission proposes to
approve PRC–005–1 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard as discussed
below.
847. Proposed Reliability Standard
PRC–005–1 does not specify the criteria
to determine the appropriate
maintenance intervals, nor does it
specify maximum allowable
maintenance intervals for the
protections systems. The Commission
therefore proposes that NERC include a
requirement that maintenance and
testing of these protection systems must
be carried out within a maximum
allowable interval that is appropriate to
the type of the protection system and its
impact on the reliability of the BulkPower System.
288 Staff identified several other PRC Reliability
Standards such as PRC–005–1, PRC–008–0, PRC–
011–0 and PRC–017–0 that contain similar
concerns.

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848. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PRC–005–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PRC–005–1 that includes a
requirement that maintenance and
testing of a protection system must be
carried out within a maximum
allowable interval that is appropriate to
the type of the protection system and its
impact on the reliability of the BulkPower System.
g. Development and Documentation of
Regional UFLS Programs (PRC–006–0)
i. NERC Proposal
849. Proposed Reliability Standard
PRC–006–0 ensures the development of
a regional UFLS program that will be
used as a last resort to preserve the
Bulk-Power System during a major
system failure that could cause system
frequency to collapse. PRC–006–0 is a
‘‘fill-in-the-blank’’ standard that
requires the regional reliability
organization to develop, coordinate,
document and assess UFLS program
design and effectiveness at least every
five years.
ii. Staff Preliminary Assessment
850. The Staff Preliminary
Assessment identified two concerns for
PRC–006–0: (1) A regional reliability
organization is identified as the sole
applicable entity; and (2) it lacks the
proper specificity for an integrated and
coordinated approach for the protection
systems for generators, transmission
lines and UFLS and UVLS programs as
recommended by the Blackout
Report.289
Staff also pointed out that the
proposed Reliability Standard requires a
periodic assessment of the effectiveness
of the regional UFLS programs and
design details at least once every five
years, which is a good example of a
maximum allowable interval without
specific justification.
iii. Comments
851. NERC claims that it is addressing
Staff’s concern that PRC–006–0 lacks an
integrated and coordinated approach to
protection for generators, transmission
289 Blackout

Report, Recommendation No. 21 at

159.

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lines and UFLS and UVLS programs
within its work on the ‘‘fill-in-theblank’’ proposed Reliability Standards.
However, NERC points out that
Requirement R3 of EOP–003–0 obligates
transmission operators and balancing
authorities to coordinate load shedding
plans among other interconnected
transmission operators and balancing
authorities.
852. Alcoa contends that proposed
Reliability Standards PRC–006–0 and
EOP–003–0 essentially assign similar
responsibilities to different entities,
thereby creating the potential for
ambiguity. It states that while EOP–003–
0 applies to transmission operators and
balancing authorities and PRC–006–0
applies to regional reliability
organizations, requirements in both
proposed Reliability Standards mandate
the design of a load shedding scheme,
including frequency set points as a
design component, under abnormal
system conditions.
853. CenterPoint believes that the
proposed Reliability Standard
adequately addresses the integration
and coordination issues, but does not
address coordination between the
generator low voltage ride-through
requirement, UVLS and dynamic
voltage recovery requirements. Further,
it states that such coordination is not
addressed by the proposed Reliability
Standard because the underlying
requirements are missing.
854. ReliabilityFirst suggests that
NERC should develop an
Interconnection-based program and use
the programs developed by the regions
within the Interconnection as a starting
point. It believes that the primary
objective of the proposed Reliability
Standards is to meet system
performance requirements and suggests
that more definitive measurable
requirements should be developed to
create an integrated and coordinated
approach to Bulk-Power System
protection.
iv. Commission Proposal
855. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
006–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with PRC–006–0 should continue on its
current basis, and the Commission
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Reliability Standard to be a matter of
good utility practice. Although we do
not propose to approve or remand with
regard to MOD–002–0 at this time, we
address comments and our additional
concerns regarding this Reliability
Standard below.
856. The Commission commends
NERC’s initiative in adopting an
integrated and coordinated approach to
protection for generators, transmission
lines and UFLS and UVLS programs
within its work on the ‘‘fill in the
blank’’ proposed Reliability Standards.
Responding to NERC’s comments on
Requirement R3 of EOP–003–0, the
Commission cautions that it only
addresses a relatively small portion of
the coordination of load shedding plans
among other interconnected entities, but
still lacks the main and overall
integration and coordination
requirements for all protection systems
in the Bulk-Power System.
857. The Commission disagrees with
Alcoa that Reliability Standards PRC–
006–0 and EOP–003–0 essentially assign
similar responsibilities to different
entities, thereby creating the potential
for ambiguity. There are distinctive
features of UFLS programs which are
designed to trip load automatically
within seconds upon detection of
abnormal system conditions due to the
imbalance of generation and load
resulting in rapidly declining
interconnected system frequencies.
Therefore, the design and coordination
of UFLS programs must be region-wide
or Interconnection-wide to ensure their
effectiveness as covered by PRC–006–0.
The load shedding plans that are
covered in EOP–003–0 are also required
as an operating measure of last resort to
address system emergencies in which
declining system frequency may not be
a prevailing indicator. Instead, system
voltages may fast approach voltage
instability, system elements may be
severely overloaded or an IROL of a
critical interface may be severely
exceeded. All of these are indicators of
an imminent threat of cascading outages
while system operators have exhausted
all available corrective actions to return
the system to a secure state. In addition,
load shedding plans usually consist of
several components including UFLS or
UVLS with different levels of response
time to facilitate load shedding. Some
load shedding capability is achieved via
remote SCADA control from the
transmission operators’ control room
and some via manual disconnection by
load serving entities under direct order
from a transmission operator or
reliability coordinator during system
emergencies. In some cases,
transmission operators may use system

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reconfiguration to disconnect large
blocks of load as a part of their load
shedding plans. The Commission views
PRC–006–0 and EOP–003–0 as two
separate and necessary Reliability
Standards and the small overlap
between the two is necessary to ensure
that effective load shedding capabilities
are available to address a wide range of
emergency operating conditions.
858. The Commission disagrees with
CenterPoint that adequate integration
and coordination is already included in
PRC–006–0 because this is contrary to
NERC’s initiative in adopting an
integrated and coordinated approach to
protection for generators, transmission
lines and UFLS and UVLS programs.
However, we support CenterPoint’s
recommendation that the generator
under-voltage ride-through capability is
an important element that should be
included in the integrated and
coordinated approach among relay
protection for generators and
transmission lines and the use of UFLS
and UVLS programs.
859. In response to ReliabilityFirst’s
suggestion to include additional
definitive measures to meet system
performance, the Commission believes
that the technical requirements should
first include the integrated and
coordinated approach in Bulk-Power
System protection, including the
frequency response of the
interconnection to load and generation
loss. Compliance Measures should be
definitive to ensure these technical
requirements are met.
h. Assuring Consistency With Regional
UFLS Program Requirements (PRC–007–
0)
i. NERC Proposal
860. Proposed Reliability Standard
PRC–007–0 requires transmission
owners, transmission operators, loadserving entities, and distribution
providers to provide, and annually
update, their under-frequency data to
facilitate the regional reliability
organization’s maintenance of, and
updates to, the UFLS program database.
Transmission owners and distribution
providers must provide documentation
of their UFLS program to the regional
reliability organization.
ii. Staff Preliminary Assessment
861. No substantive issues were
identified regarding PRC–007–0.
iii. Comments
862. CPUC states that PRC–007–0 is
an example of a Reliability Standard
that should be mandatory on a national
level, but for which it is appropriate for
the details of implementation to be

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delegated to a regional reliability
organization. ISO/RTO Council states
that PRC–007–0 fails to define an
acceptable UFLS program.
iv. Commission Proposal
863. With regard to ISO/RTO
Council’s comment, the specification of
an acceptable UFLS program is the
subject of PRC–006–0. In contrast, PRC–
007–0 provides that, if an entity has a
UFLS program, the program must be
consistent with its regional reliability
organization’s requirements.
864. The Commission believes that
there are no substantive issues with this
proposed Reliability Standard. We note
that, once approved, the proposed
Reliability Standard will be applied and
enforced on a national scale as
suggested by CPUC.
865. Accordingly, the Commission
proposes to approve PRC–007–0 as
mandatory and enforceable. We believe
that the proposed Reliability Standard is
just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
i. Under Frequency Load Shedding
Equipment Maintenance Programs
(PRC–008–0)
i. NERC Proposal
866. Proposed Reliability Standard
PRC–008–0 requires transmission
owners and distribution providers to
implement UFLS equipment
maintenance and testing programs and
provide program results to the regional
reliability organization.
ii. Staff Preliminary Assessment
867. According to the Staff
Preliminary Assessment, PRC–008–0
does not specify the criteria to
determine appropriate maintenance
intervals or the maximum allowable
interval to ensure effectiveness, as
discussed in detail in the Staff
Preliminary Assessment section of this
rulemaking under PRC–005–1. No other
substantive issues were identified for
this proposed Reliability Standard.

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iii. Comments
868. Commenter’s statements
regarding maximum allowable intervals
for the performance of maintenance and
testing programs have been presented in
detail under the comments for PRC–
005–1.
iv. Commission Proposal
869. The Commission notes that the
commenters generally share staff’s
concern that the proposed Reliability
Standard does not specify the criteria to
determine the appropriate maintenance
intervals, nor does it specify maximum

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allowable maintenance intervals for the
protection systems. The Commission
agrees and proposes to require NERC to
modify the proposed Reliability
Standard to include a requirement that
maintenance and testing of UFLS
programs must be carried out within a
maximum allowable interval that is
appropriate to the type of relay used and
the impact on the reliability of the BulkPower System.
870. Accordingly, the Commission
proposes to approve Reliability
Standard PRC–008–0 as mandatory and
enforceable. In addition, the
Commission proposes to direct that
NERC submit a modification to PRC–
008–0 that includes a requirement that
maintenance and testing of UFLS
programs must be carried out within a
maximum allowable interval
appropriate to the relay type and the
potential impact on the Bulk-Power
System.
j. UFLS Performance Following an
Under Frequency Event (PRC–009–0)
i. NERC Proposal
871. Proposed Reliability Standard
PRC–009–0 ensures that the
performance of an UFLS system is
analyzed and documented following an
under frequency event by requiring the
transmission owner, transmission
operator, load-serving entity and
distribution provider to document their
operation in accordance with the
regional reliability organization’s
program and to provide that
documentation to the regional reliability
organization and NERC upon their
request.
ii. Staff Preliminary Assessment
872. Staff noted that, although the
proposed Reliability Standard contains
the reporting requirement for operation
events for UFLS, there is no similar
reporting requirement for operation
events for UVLS in the proposed
Reliability Standards that are associated
with UVLS programs.
iii. Comments
873. ReliabilityFirst supports the
development of a companion UVLS
Reliability Standard with reporting
requirements that are similar to this
UFLS Reliability Standard. Likewise,
NERC acknowledges the concerns of the
Staff Preliminary Assessment, noting
the lack of a reporting requirement for
operation events of UVLS and plans to
address this omission in its work on the
‘‘fill-in-the-blank’’ proposed Reliability
Standards that are associated with
UVLS.
874. ISO/RTO Council states that, due
to the fact that PRC–009–0

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inappropriately relies on the undefined
UFLS programs of regional reliability
organizations, NERC must review and
approve the regional reliability
organizations’ programs before the
proposed Reliability Standard can go
into effect.
875. TAPS states that PRC–009–0
requires distribution providers with a
transmission protection program to
analyze an under-frequency event and
document the post-mortem. It cautions
that it may be difficult and unduly
burdensome for a small entity to
perform given limited access to event
data and the need to perform a stability
analysis.
876. CenterPoint suggests adopting a
performance metric approach rather
than a ‘‘fill-in-the-blank’’ approach to
this Reliability Standard. It contends
that compliance should be
straightforward since transmission and
distribution service providers are
supposed to trip a certain amount of
load under specified under-frequency
conditions. Therefore, either the utility
tripped the required amount of load or
it did not, perhaps with some
bandwidth.
iv. Commission Proposal
877. The Commission discusses ISO/
RTO Council’s comments on the general
issue that regional Reliability Standards
must be approved by the ERO and the
Commission before they become
effective above in the section on
Common Issues.
878. The Commission does not find
any material difference between
CenterPoint’s suggestion to use a
performance metric approach and the
Requirements in this proposed
Reliability Standard. We believe
performance metrics, especially leading
metrics, are excellent complementary
components in Reliability Standards
which enable further enhancement and
effectiveness of these Reliability
Standards.
879. With respect to TAPS’ concern
regarding the size of distribution
providers and load serving entities, the
Commission discusses this issue in the
Common Issues section of this NOPR.
880. The Commission believes that
the proposal serves an important
purpose in ensuring that the
performance of an UFLS system is
analyzed and documented following an
under frequency event. Further the
proposed Requirements are sufficiently
clear and objective to provide guidance
for compliance. Accordingly, the
Commission proposes to approve PRC–
009–0 as mandatory and enforceable.
We believe that the proposed Reliability
Standard is just, reasonable, not unduly

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discriminatory or preferential, and in
the public interest.
k. Assessment of the Design and
Effectiveness of UVLS Program (PRC–
010–0)
i. NERC Proposal
881. Proposed Reliability Standard
PRC–010–0 requires transmission
owners, transmission operators, loadserving entities, and distribution
providers to periodically conduct and
document an assessment of the
effectiveness of the UVLS program.290
This assessment shall be conducted
with the associated transmission
planner and planning authority.
ii. Staff Preliminary Assessment
882. The Staff Preliminary
Assessment raised the concern that this
proposed Reliability Standard on UVLS,
similar to PRC–006–0 on UFLS, is not
specific enough to address Blackout
Report Recommendation No. 21
concerning an integrated and
coordinated approach for the protection
systems for generators, transmission
lines and UFLS and UVLS programs.291

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iii. Comments
883. NERC states that it has made
progress in responding to Blackout
Recommendation No. 21 on the
Evaluation of Applicability of UVLS
programs. The NERC Planning
Committee reviewed each regional
reliability organization’s assessment of
the feasibility and benefits of installing
UVLS capability. In addition, the NERC
Planning Committee has completed a
report entitled, ‘‘Review of Regional
Evaluations of Under-voltage Load
Shedding Capability in Response to
NERC Blackout Recommendation
8b,’’ 292 with follow-up
recommendations to be completed by
the NERC Planning Committee and the
regions, along with an implementation
plan. NERC further states that the work
is ongoing under the supervision of the
NERC Planning Committee and will
result in requests for new standards as
the work is completed and suitable
methods and criteria are developed.
884. CenterPoint questions the need
for this Reliability Standard and the
other three Reliability Standards that
address other UVLS requirements,293
while acknowledging that there is a
significant need for UVLS for some
systems. CenterPoint contends that it is
290 At least every five years or as required by
changes in system conditions.
291 Blackout Report at 159.
292 Available at http://www.nerc.com/∼filez/
reports.html.
293 PRC–010–0, PRC–020–1 and PRC–021–1.

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unreasonable and unnecessary to
require examination and documentation
of any and all UVLS trips. Further, it
states that producing unnecessary
Reliability Standards for utilities that
install UVLS schemes could have the
adverse effect of discouraging utilities
that might benefit from UVLS by
installing the schemes or, alternatively,
punishing the utilities that do so.
885. MEAG seeks a clarification in the
specific instance where the transmission
owner owns and maintains a
transmission protection system, e.g., a
UFLS or UVLS system, and where some
of the associated relays are designed to
trip a distribution breaker owned by a
customer.
886. ReliabilityFirst suggests an
integrated and coordinated approach to
Bulk-Power System protection, as
discussed above in the context of PRC–
006–0.
iv. Commission Proposal
887. The Commission commends the
initiative and efforts that have been
taken by NERC and industry in
addressing UVLS requirements as
recommended by the Blackout Report
and expects to review these
improvements in the proposed
Reliability Standards associated with
UVLS in their future revisions.
888. The Commission believes that
Reliability Standards of UVLS are
required in the same manner as
Reliability Standards for line and
generation protection, UFLS or special
protection systems since all of them are
required to ensure reliable system
operation. Therefore, we disagree with
CenterPoint’s view that UVLS
Reliability Standards are not necessary.
889. In response to a question raised
by MEAG regarding the ownership of an
UFLS or UVLS installed by a
transmission owner on a breaker owned
by a customer, the transmission owner
remains the owner. The transmission
owner or transmission operator can trip
the breaker automatically or have a
delegated agreement with the customer
to trip the breaker in case of an UFLS
or UVLS event. The Commission
believes that the Reliability Standard
should be interpreted to achieve its
reliability goal. This can be
accomplished by each entity performing
their required maintenance and
operational activities or by one entity
doing the required activities. However,
the UFLS or UVLS system must be
maintained from the sensors that detect
the event to the actual opening of the
circuit breaker.
890. In response to ReliabilityFirst’s
suggestion to include additional
definitive measures to meet system

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64851

performance, the Commission believes
that the technical requirements should
include an integrated and coordinated
approach in Bulk-Power System
protection, including the frequency
response of the interconnection to load
and generation loss. Compliance
Measures should be definitive to ensure
these technical requirements are met.
891. The Commission believes that
Reliability Standard PRC–010–0 serves
an important purpose in requiring the
periodical assessment of the
effectiveness of a UVLS program.
Further, the proposed Requirements are
sufficiently clear and objective to
provide guidance for compliance.
892. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PRC–010–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PRC–010–0 that requires that an
integrated and coordinated approach be
included in all protection systems on
the Bulk-Power System, including
generators and lines, generator’s low
voltage ride-through capabilities, and
UFLS and UVLS programs.
l. Under Voltage Load Shedding System
Maintenance and Testing (PRC–011–0)
i. NERC Proposal
893. Proposed Reliability Standard
PRC–011–0 requires transmission
owners and distribution providers to
implement their UVLS equipment
maintenance and testing program and
provide program results to regional
reliability organization.
ii. Staff Preliminary Assessment
894. Staff expressed concern that
PRC–011–0 does not specify the criteria
to determine the appropriate
maintenance intervals or maximum
allowable intervals for protection
systems to ensure effectiveness has been
articulated in detail in the same section
in PRC–005–1.
iii. Comments
895. NERC indicates that it will
consider maximum intervals; and ISO/
RTO Council and other commenters

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agree with the Staff Preliminary
Assessment.294
iv. Commission Proposal
896. PRC–011–0 does not specify the
criteria to determine the appropriate
maintenance intervals, nor does it
specify maximum allowable
maintenance intervals for the
protections systems. The Commission
proposes that NERC include a
Requirement that maintenance and
testing of these UFLS programs must be
carried out within a maximum
allowable interval that is appropriate to
the type of the relay used and the
impact of these UFLS on the reliability
of the Bulk-Power System.
897. The Commission believes that
Reliability Standard PRC–011–0 serves
an important purpose in requiring
transmission owners and distribution
providers to implement their UVLS
equipment maintenance and testing
programs. Further, the proposed
Requirements are sufficiently clear and
objective to provide guidance for
compliance.
898. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PRC–011–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PRC–011–0 that includes a
requirement that maintenance and
testing of UVLS programs must be
carried out within a maximum
allowable interval appropriate to the
applicable relay and the impact on the
reliability of the Bulk-Power System.
m. Special Protection System Review
Procedure (PRC–012–0)

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i. NERC Proposal
899. Proposed Reliability Standard
PRC–012–0 requires regional reliability
organizations to ensure that all special
protection systems 295 are properly
designed, meet performance
requirements and are coordinated with
294 While commenters raise these concerns
primarily in the context of PRC–005–1, their
comments apply to PRC–011–0 as well.
295 A special protection system is a unique system
designed to automatically take corrective actions to
protect the system under abnormal or
predetermined conditions, excluding the
coordinated tripping of circuit breakers to isolate
faulted components, which is typically the purpose
of other protection devices.

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other protection systems. Maintenance
and testing programs must be developed
and special protection system
misoperations must be analyzed and
corrected.
ii. Staff Preliminary Assessment
900. Similar to its discussion of PRC–
002–1, staff noted that Reliability
Standard designates a regional
reliability organization as the sole
applicable entity.
iii. Comments
901. A number of commenters
discussed how the Commission should
address PRC–012–0 and other fill-inthe-blank standards in the PRC group
that require compliance by regional
reliability organizations.296
iv. Commission Proposal
902. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
012–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with PRC–012–0 should continue on its
current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
n. Special Protection System Database
(PRC–013–0)
i. NERC Proposal
903. Proposed Reliability Standard
PRC–013–0 ensures that all special
protection systems are properly
designed, meet performance
requirements and are coordinated with
other protection systems by requiring
the regional reliability organization to
maintain a database of pertinent
information on special protection
systems.
ii. Staff Preliminary Assessment
904. Similar to its discussion of PRC–
002–1, staff noted that this Reliability
Standard designates a regional
reliability organization as the sole
applicable entity.
296 296 CPUC, FRCC, National Grid, NPCC,
NYSRC, ReliabilityFirst, Southern and TANC. Their
comments also apply to PRC–003–1, PRC–006–0,
PRC–012–0, PRC–013–0; PRC–014–0 and PRC–020–
1.

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iii. Comments
905. A number of commenters
discussed how the Commission should
address PRC–012–0 and other fill-inthe-blank standards in the PRC group
that require compliance by regional
reliability organizations.
906. ISO/RTO Council states that this
Reliability Standard identifies only
categories rather than the detailed data
useful for ensuring that a meaningful
special protection system database is
maintained.
907. National Grid identifies this
Reliability Standard as one of those it
refers to as ‘‘procedurally regional.’’
That is, the requirement is set on a
national level but is implemented
regionally. In the case of PRC–013–0, all
relevant entities would be required to
provide information to databases
established and maintained by some
regional body. National Grid explains
that this is one example of a legitimate
‘‘fill-in-the-blank’’ Reliability Standard.
iv. Commission Proposal
908. The Commission believes that
the current Requirements and Measures
in the proposed Reliability Standard are
adequate, and therefore, disagrees with
ISO/RTO Council’s comments in this
regard. Requirement R1 includes three
categories of data with each category
providing a more detailed description of
required data. Measure M1 requires that
each owner with a special protection
system must have the corresponding
database as specified in the proposed
Reliability Standard.
909. We agree with National Grid that
the database should be maintained on a
regional basis. However, Regional
Entities have not undergone an approval
process under section 215. Therefore,
we cannot yet enforce this requirement.
910. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
013–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance
with PRC–013–0 should continue on its
current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.

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o. Special Protection System
Assessment (PRC–014–0)
i. NERC Proposal
911. Proposed Reliability Standard
PRC–014–0 ensures that special
protection systems are properly
designed, meet performance
requirements, and are coordinated with
other protection systems by requiring
the regional reliability organization to
assess and document the operation,
coordination, compliance with NERC
Reliability Standards, as well as the
effectiveness of special protection
systems, at least once every five years.
ii. Staff Preliminary Assessment
912. Similar to its discussion of PRC–
002–1, staff noted that this Reliability
Standard designates a regional
reliability organization as the sole
applicable entity.
913. The Staff Preliminary
Assessment noted that the maximum
allowable interval of at least once every
five years as a Requirement for assessing
the effectiveness of the special
protection systems is a good example of
a maximum allowable interval without
specific justification.
iii. Comments
914. A number of commenters
discussed how the Commission should
address PRC–012–0 and other fill-inthe-blank standards in the PRC group
that require compliance by regional
reliability organizations.
iv. Commission Proposal
915. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
014–0 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits the regional
procedures or a single continent-wide
procedure. In the interim, compliance
with PRC–014–0 should continue on its
current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.

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p. Special Protection System Data and
Documentation (PRC–015–0)
i. NERC Proposal
916. Proposed Reliability Standard
PRC–015–0 requires transmission
owners, generator owners, and
distribution providers to maintain a
listing, retain evidence of review, and

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provide documentation for existing,
new, or functionally modified special
protection systems.
ii. Staff Preliminary Assessment
917. No substantive issues were
identified for the proposed Reliability
Standard.
iii. Comments
918. The ISO/RTO Council believes
that the time period used for assessing
compliance is not clear in this
Reliability Standard.
iv. Commission Proposal
919. The Commission believes that
there are no substantive issues
identified for this proposed Reliability
Standard.
920. We disagree with ISO/RTO
Council’s view that the compliance time
period is not clear. Requirement 3 of
this Reliability Standard requires
documentation to be provided within 30
days for compliance requirements.
921. Accordingly, the Commission
proposes to approve PRC–015–0 as
mandatory and enforceable. We believe
that the proposed Reliability Standard is
just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
q. Special Protection System
Misoperations (PRC–016–0)
i. NERC Proposal
922. Proposed Reliability Standard
PRC–016–0 requires transmission
owners, generator owners and
distribution providers to provide the
regional reliability organization with
documentation, analyses and corrective
action plans for misoperation of special
protection systems.
ii. Staff Preliminary Assessment
923. No substantive issues were
identified for the proposed Reliability
Standard.
iii. Comments
924. ISO/RTO Council is concerned
that this Reliability Standard fails to
identify the analysis sufficient for
reviewing special protection system
operations and the type of corrective
action that must be taken to avoid
misoperations. It also believes that
reports on special protection system
misoperations should be routinely
provided to the regional reliability
organization and NERC.
iv. Commission Proposal
925. We disagree with ISO/RTO
Council that PRC–016–0 does not
identify the analysis sufficient for
reviewing special protection systems

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and the type of corrective actions
required to avoid misoperations.
However, we agree that reports on
special protection system misoperations
should be routinely provided to the
regional reliability organization and
NERC and propose to require NERC to
provide that routine reporting be limited
to misoperations of special protection
systems that have Interconnection-wide
reliable impact and routine submission
of the corrective action plans upon
implementation instead of the current
requirement of 90 days upon request.
926. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PRC–016–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PRC–016–0 that includes a
requirement that maintenance and
testing of these special protection
system programs must be carried out
within a maximum allowable interval
that is appropriate for the type of
relaying used and the impact of these
special system protection programs on
the reliability of the Bulk-Power System.
r. Special Protection System
Maintenance and Testing (PRC–017–0)
i. NERC Proposal
927. Proposed Reliability Standard
PRC–017–0 requires transmission
owners, generator owners, and
distribution providers to provide the
regional reliability organization with
documentation on special protection
system maintenance, testing and
implementation plans.
ii. Staff Preliminary Assessment
928. Staff expressed concern that this
Reliability Standard does not specify the
criteria to determine the appropriate
maintenance intervals or maximum
allowable intervals for protection
systems to ensure effectiveness.
iii. Comments
929. The comments provided by ISO/
RTO Council and NERC regarding
maximum allowable intervals in
carrying out maintenance and testing
programs in the PRC Reliability
Standards have been presented in detail
in PRC–005–1.

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iv. Commission Proposal
930. PRC–017–0 does not specify the
criteria to determine the appropriate
maintenance intervals, nor does it
specify maximum allowable
maintenance intervals for the
protections systems. The Commission
proposes to require NERC to include a
requirement that maintenance and
testing of these special protection
system programs must be carried out
within a maximum allowable interval
that is appropriate to the type of
relaying used and the impact of these
special protection system programs on
the reliability of the Bulk-Power System.
931. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard PRC–017–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to PRC–017–0 that: (1) Includes a
requirement that maintenance and
testing of these special protection
system programs must be carried out
within a maximum allowable interval
that is appropriate to the type of
relaying used; and (2) identifies the
impact of these special protection
system programs on the reliability of the
Bulk-Power System.
s. Disturbance Monitoring Equipment
Installation and Data Reporting (PRC–
018–1)
i. NERC Proposal
932. Proposed Reliability Standard
PRC–018–1 ensures that disturbance
monitoring equipment is installed and
disturbance data is reported in
accordance with comprehensive
requirements for installing disturbance
monitoring equipment.
ii. Staff Preliminary Assessment
933. This is a new Reliability
Standard and it was not assessed in the
Staff Preliminary Assessment.

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iii. Comments
934. Because this Reliability Standard
was not discussed in the Staff
Preliminary Assessment, no comments
have been filed.
iv. Commission Proposal
935. The Commission notes that the
proposed Reliability Standard addressed
Blackout Report Recommendation No.

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28 by requiring the transmission owner
and generator owner to install
disturbance monitoring equipment and
report disturbance data. The
Commission commends the initiative
and efforts taken by NERC and industry
in addressing this recommendation.
936. Accordingly, the Commission
proposes to approve PRC–018–1 as
mandatory and enforceable. We believe
that the proposed Reliability Standard is
just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
t. Under-Voltage Load Shedding
Program Database (PRC–020–1)
i. NERC Proposal
937. Proposed Reliability Standard
PRC–020–1 ensures that a regional
database for UVLS programs is available
for Bulk-Power System studies by
requiring regional reliability
organizations with any entities that have
UVLS programs to maintain and
annually update a database.
ii. Staff Preliminary Assessment
938. Staff noted that this version 1
Reliability Standard was recently
approved by the NERC Board of
Trustees, effective May 1, 2006, and
does not address the applicability
concerns articulated in the Staff
Preliminary Assessment.
939. In addition, similar to its
discussion of PRC–002–1, staff noted
that this Reliability Standard designates
a regional reliability organization as the
sole applicable entity. Staff was
concerned about the feasibility of a
regional reliability organization serving
as the applicable entity and the
enforceability of the proposed
Reliability Standard in the mandatory
Reliability Standards structure.
iii. Comments
940. A number of commenters
discussed how the Commission should
address PRC–020–0 and other fill-inthe-blank standards in the PRC group
that require compliance by regional
reliability organizations.
iv. Commission Proposal
941. Because the regional procedures
have not been submitted to the
Commission, it is not possible to
determine at this time whether PRC–
020–1 satisfies the statutory requirement
that a proposed Reliability Standard be
‘‘just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.’’ Accordingly, the
Commission will not propose to accept
or remand this Reliability Standard
until the ERO submits additional
information. In the interim, compliance

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with PRC–020–1 should continue on its
current basis, and the Commission
considers compliance with the
Reliability Standard to be a matter of
good utility practice.
u. Under-Voltage Load Shedding
Program Data (PRC–021–1)
i. NERC Proposal
942. Proposed Reliability Standard
PRC–021–1 ensures that data is
supplied to support the regional UVLS
database by requiring the transmission
owner and distribution provider to
supply data related to its system and
other related protection schemes to its
regional reliability organization’s data
base.
ii. Staff Preliminary Assessment
943. No substantive issues were
identified for the proposed Reliability
Standard PRC–021–1.
iii. Comments
944. CenterPoint seems to promote
eliminating this Reliability Standard as
stated previously in PRC–010–0.
iv. Commission Proposal
945. The Commission believes that
Reliability Standards for UVLS are
required in the same manner as
Reliability Standards for line and
generation protection, UFLS or special
protection systems since all of them are
required to ensure reliable system
operations. Therefore, we disagree with
CenterPoint’s view that UVLS
Reliability Standards are not needed.
946. The Commission proposes to
approve, as mandatory and enforceable,
Reliability Standard PRC–021–1 as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.
v. Under-Voltage Load Shedding
Program Performance (PRC–022–1)
i. NERC Proposal
947. Proposed Reliability Standard
PRC–022–1 requires transmission
operators, load-serving entities, and
distribution providers to provide
analysis, documentation on UVLS
operations and misoperations to the
regional reliability organization.
ii. Staff Preliminary Assessment
948. No substantive issues were
identified regarding Reliability Standard
PRC–022–1.
iii. Comments
949. No comments were filed.
iv. Commission Proposal
950. The Commission believes that
there are no substantive issues for this

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proposed Reliability Standard.
Therefore, the Commission proposes to
approve, as mandatory and enforceable,
Reliability Standard PRC–022–1 as just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.

ii. Staff Preliminary Assessment
953. The Staff Preliminary
Assessment did not identify any
substantive issues regarding TOP–001–
0, other than noting that it does not
contain Measures or Levels of NonCompliance.

11. TOP: Transmission Operations

iii. Comments
954. MEAG states that, under
Requirement R2 a transmission operator
must take immediate actions to shed
load to alleviate an emergency, and
Requirement R4 obligates distribution
providers and load-serving entities to do
the same. MEAG contends that
Requirement R4 should be eliminated
because, to the extent that a
transmission owner relies on a
distribution provider or load serving
entity to respond to a system
emergency, including load shedding,
this should be done through a formal
agreement with specific protocols that
all parties have agreed to follow. MEAG
states that, as long as Requirement R4 is
included in the Reliability Standard, an
entity may make faulty assumptions
about the emergency response of
another entity.
955. MRO states that Requirements
7.1, 7.2, and 7.3, which relate to
coordination when a generation or
transmission facility is removed from
service, appear to be instructions rather
than requirements. It asks the
Commission to revise or remove these
Requirements.

a. Overview
951. The eight proposed Transmission
Operations (TOP) Reliability Standards
apply to transmission operators,
generator operators and balancing
authorities. The goal of these Reliability
Standards is to ensure that the
transmission system is operated within
operating limits. Specifically, these
Reliability Standards cover the
responsibilities and decision-making
authority for reliable operations,
requirements for operations planning,
planned outage coordination, real-time
operations, provision of operating data,
monitoring of system conditions,
reporting of operating limit violations
and actions to mitigate such violations.
The Interconnection Reliability
Operations and Coordination (IRO)
group of Reliability Standards
complement these proposed TOP
Reliability Standards.
b. Reliability Responsibilities and
Authorities (TOP–001–0)

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i. NERC Proposal
952. TOP–001–0 requires that: (a) The
transmission operating personnel must
have the authority to direct actions in
real-time; (b) the transmission operator,
balancing authority, and generator
operator must follow the directives of
their reliability coordinator; and (c) the
balancing authority and generator
operator must follow the directives of
the transmission operator. In addition,
the proposed Reliability Standard
requires the transmission operator,
balancing authority, generator operator,
distribution provider and load-serving
entity to take emergency actions when
directed to do so in order to keep the
transmission system intact. The
reliability goal of TOP–001–1 is to: (1)
Ensure that system operators have the
authority to take actions and direct
others to take action to maintain BulkPower System facilities within limits;
(2) protect transmission, generation,
distribution, and customer equipment;
and (3) prevent cascading failures of the
interconnected grid. Further, NERC
indicates that it plans to modify TOP–
001–0 to address the lack of Measures
and Levels of Non-Compliance.

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iv. Commission Proposal
956. The Commission proposes to
approve TOP–001–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
957. Requirement R1 of TOP–001–0
states that a transmission operator must
have the responsibility and clear
decision-making authority ‘‘to take
whatever actions are needed to ensure
the reliability of its area.’’ Neither the
Reliability Standard nor the NERC
glossary explains what is meant by a
transmission operator’s ‘‘area.’’ We
interpret the term to mean the area in
which the transmission facilities under
the transmission operator’s control are
located.297
958. We are not persuaded by MEAG’s
suggestion to eliminate Requirement R4
297 We note that NERC’s reliability functional
model (Function Definitions and Responsible
Entities, version 2, approved by the Board of
Trustees Feb. 10, 2004) defines Reliability
Authority Area, Balancing Authority Area,
Transmission Planning Area, and Planning
Authority Area, but does not define Transmission
Operator Area.

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and utilize a formal agreement to
determine the response of a distribution
provider or load serving entity to a
system emergency. As set forth in
Requirement R1, each transmission
operator must have the responsibility
and corresponding decision-making
authority to take ‘‘whatever actions are
needed’’ to ensure reliability in an
emergency. This includes the
curtailment of transmission service and
load shedding. Eliminating the general
obligation set forth in Requirement R4
that a distribution provider or load
serving entity must ‘‘comply with all
reliability directives of the transmission
operator * * * unless such action
would violate safety, equipment,
regulatory or statutory requirements,’’
and replacing it with formal agreements
would result not only in regional
differences but differences in the ability
of a transmission operator to respond to
an emergency on a system-by-system
and contract-by-contract basis. Rather
than enhancing reliability, we believe
that such latitude could result in the
deterioration of Bulk-Power System
reliability.
959. MRO claims that Requirements
R7.1, R7.2, and R7.3 appear to be
instructions rather than requirements.
Requirement R7 provides that each
transmission operator and generator
operator shall not remove facilities from
service if removing those facilities
would burden a neighboring system
unless certain events occur that are
delineated in Requirements R7.1, R7.2
and R7.3. While MRO does not explain
what it considers to be the difference
between an instruction and a
requirement, we interpret that, read
together as a whole Requirement R7
articulates binding obligations on a
transmission operator and is properly
characterized as a requirement.
960. As mentioned above, TOP–001–
0 does not contain Measures or Levels
of Non-Compliance. However, we
believe that the Requirements set forth
in TOP–001–0 are sufficiently clear and
objective to provide guidance for
compliance. Moreover, TOP–001–0
serves the vital purpose of ensuring that
transmission operators and others have
clear decision-making authority to take
appropriate actions or direct the actions
of others to return the transmission
system to normal conditions during an
emergency.
961. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to

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approve Reliability Standard TOP–001–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–001–0 that includes Measures
and Levels of Non-Compliance.
c. Normal Operations Planning (TOP–
002–1)
i. NERC Proposal
962. TOP–002–1 requires
transmission operators and balancing
authorities to look ahead to the next
hour, day and season, and have
operating plans ready to meet any
unscheduled changes in system
configuration and generation dispatch.
The proposed Reliability Standard
covers a broad array of matters,
including: (1) Procedures to mitigate
System Operating Limit (SOL) and
Interconnection Reliability Operating
Limit (IROL) violations; (2) verification
of real and reactive reserve capabilities;
(3) communications; (4) modeling; (5)
information exchange; and (6) data
confidentiality restrictions. The goal of
TOP–002–1 is to ensure that resources
and operational plans are in place to
enable system operators to maintain the
Bulk-Power System in a reliable state.
Further, NERC indicates that it plans to
modify the Reliability Standard to
address the lack of Measures and Levels
of Non-Compliance.
963. Two Requirements of particular
note are R7 and R14. Requirement R7 of
TOP–002–1 provides that each
balancing authority shall plan to meet
capacity and energy reserve
requirements, including being able to
deliver power in the case of any single
contingency. Requirement R14 directs
each generator operator to notify its
balancing authority and transmission
operator of changes in: (1) real and
reactive power output capabilities.298
ii. Staff Preliminary Assessment

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964. The Staff Preliminary
Assessment noted that Requirement R7
specifies that capacity and energy
reserves must be deliverable to local
areas in case of a single contingency.299
Other Reliability Standards require that
the system operate in a manner that
298 On August 28, 2006, NERC submitted TOP–
002–1 for approval, which replaces TOP–002–0.
TOP–002–1 simply deletes the Requirement R14.2,
which required automatic voltage regulators.
According to NERC, the deleted requirement is now
included in the recently revised VAR–001–1 and is
therefore unnecessary in TOP–002–1.
299 Although the Staff Preliminary Assessment
addresses concerns regarding the TOP–002–0, many
of these same concerns apply to TOP–002–1 as
well.

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allows it to be returned to a stable state
within 30 minutes after a contingency
occurs with the capacity to withstand
another contingency without
cascading.300 In contrast, the Reliability
Standard does not require the next-day
planning analysis to identify control
actions that are needed to bring the
system back to a stable state within 30
minutes after a contingency occurs with
the capacity to withstand another
contingency without cascading.301 The
Staff Preliminary Assessment noted that
this may present a potential
vulnerability as operators may not be
aware of available control actions or
may not have control actions, other than
firm load shedding, available to adjust
the system after a first contingency
occurs.
965. The Staff Preliminary
Assessment also pointed out a potential
gap in the analysis of and planning for
contingencies. This Reliability Standard
refers to a ‘‘single contingency’’ and is
defined as the loss of a transformer,
transmission circuit, single DC pole or
generator, but does not include the
assessment of outages of multiple
elements that would be removed from
service as a result of a single component
failure.302 Thus, the loss of a single
relay, breaker, control system
component or transmission tower may
affect multiple system elements.
However, these circumstances are not
required to be considered in the analysis
of, and planning for, contingencies.
966. Finally, the Staff Preliminary
Assessment stated that, although
Requirement R14 of the Reliability
Standard recognizes the need to
communicate changes in generator ‘‘real
and reactive capability as well as the
status of automatic voltage regulators,’’
it does not include a similar
requirement to communicate changes in
the status of power system stabilizers.
iii. Comments
967. NERC states that, contrary to the
Staff Preliminary Assessment,
Requirement R11 of the Reliability
Standard does require next-day studies.
NERC further states that next-day
analysis should not have to identify
control actions. Rather, it is intended to
provide a look into the next day so that
the transmission operator can then
300 See

proposed Reliability Standard IRO–005–1.
operators should operate the BulkPower System such that firm load will continue to
be supplied after a contingency. The operations
planning function should provide the system
operators with information (control actions)
concerning what actions may be needed to avoid
cascading after the worst contingency has occurred.
302 Failure of an electrical component includes
relay and control system failures, which may
remove more than one element.
301 System

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develop operating strategies.
Appropriate real-time control actions
may diverge from those identified by a
transmission operator’s previous-day
studies, and therefore, according to
NERC, the Reliability Standard does not
identify control actions to be followed
by the operators. Similarly, NERC states
that it is impractical to identify and
study all possibilities in next-day
analysis.
968. Regarding staff’s concern
regarding the lack of analysis of
multiple system elements, NERC
responds that Requirement R6 instructs
each balancing authority and
transmission operator to meet NERC,
regional reliability organization,
subregional and local reliability
requirements. Thus, the Reliability
Standard recognizes that some
situations require operating in a manner
that provides protection against the
failure of multiple system elements.
However, NERC adds that it will review
Requirement R7 to ensure that reserves
can be deployed to meet the
requirements of the disturbance control
Reliability Standard, BAL–002–0.
969. MidAmerican and MRO point
out that the availability for the sale of
short-term firm transmission service is
based on calculations taking into
account single element events. Any
effort to define single contingencies in
terms of multiple elements will result in
a significant decrease in available
transmission capability; resulting in a
negative impact on competition in the
wholesale market. MRO also maintains
that technology does not allow for
comprehensive assessment of outages of
multiple elements due to a single
component failure.
970. Regarding the Staff Preliminary
Assessment’s statement that the status
of power system stabilizers should be
communicated in TOP–002–0, NERC
notes that this is covered by a separate
Reliability Standard, VAR–001–0, under
Requirements R4 and R9.
971. Requirements R3 and R4 provide
that each load serving entity and
generator operator shall coordinate its
operations with its balancing authority
and transmission service provider,
‘‘where confidentiality agreements
allow.’’ Alcoa objects to this phrase,
contending that a load serving entity or
generator operator may evade these
coordination requirements by simply
not executing a confidentiality
agreement.
iv. Commission Proposal
972. The Commission proposes to
approve TOP–002–1 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications

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to the Reliability Standard, as discussed
below.
973. While Requirement R11 requires
next day studies, as mentioned above,
TOP–002–1 does not require the nextday planning analysis to identify control
actions that are needed to bring the
system back to a stable state within 30
minutes after a contingency occurs with
the capacity to withstand another
contingency without cascading.
Operators should have at their disposal
and be aware of control actions to adjust
the Bulk-Power System within 30
minutes to avoid cascading after the
worst contingency has occurred. Such
control actions include reconfiguring
the transmission system, recalling
facilities from planned outages, and
ensuring availability of generation and
reactive power resources. These control
actions should be determined as part of
day ahead operations planning. While
NERC suggests that it would be
impractical to study every possibility to
identify control actions, we believe that
in fact only a limited number of critical
facilities associated with IROLs would
require analysis to identify control
actions aimed at avoiding cascading
outages. Accordingly, we propose
directing that NERC modify TOP–002–
1 to include identification of control
actions that can be implemented within
30 minutes as a part of the next-day
analysis and communication of these
control actions to system operators.
974. NERC’s glossary defines
‘‘contingency’’ as ‘‘the unexpected
failure or outage of a system component,
such as a generator, transmission line,
circuit breaker, switch or other electric
element.’’ 303 Requirement R7 of TOP–
002–1 requires that each balancing
authority plan to meet capacity and
energy reserve requirements, including
deliverability/capability for any single
contingency.304 Although the NERC
glossary defines ‘‘contingency,’’ we are
concerned that the phrase ‘‘single
contingency’’ is open to interpretation
and that deliverability is not defined.
The Commission proposes to interpret
contingency as discussed in the
transmission planning chapter and to
interpret deliverability as the ability to
deliver the output from generation
resources to firm load without any
reliability criteria violations for
plausible generation dispatches.
975. The Staff Preliminary
Assessment suggested that TOP–002–0
should include a requirement to
communicate a change in the status of
power system stabilizers. In response,
NERC comments that this is addressed
303 NERC
304 See

glossary at 3.
R7 of TOP–002–0.

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in VAR–001–0, which requires that each
generator operator provide information
to its transmission operator on the status
of generation reactive power resources
including the status of power system
stabilizers. We agree with NERC and do
not propose any changes in this regard.
976. We share Alcoa’s concern
regarding the possible interference with
the coordination demanded in
Requirements R3 and R4 if that
coordination is dependent upon the
execution of a confidentiality
agreement. Generally, the effectiveness
of a Reliability Standard should not be
predicated upon the existence of a
confidentiality agreement or any other
private agreement. If some Reliability
Standards require a confidentiality
agreement, the Commission believes
that the matter should be addressed
separately and globally so that it applies
to all Reliability Standards rather than
designating that a specific requirement
is subject to existence of a
confidentiality agreement. Accordingly,
we propose to direct that NERC modify
Requirements R3 and R4 by deleting
references to confidentiality agreements.
Rather, NERC should address the issue
separately to ensure that necessary
protections are in place related to
confidential information.
977. While we have identified
concerns with regard to TOP–002–1, we
believe that the proposed Reliability
Standard serves an important purpose
in ensuring that resources and
operational plans are in place to enable
system operators to maintain the BulkPower System in a reliable state. As
mentioned above, TOP–002–1 does not
contain Measures or Levels of NonCompliance. The Commission believes
that it is important for NERC to provide
Measures and Levels of NonCompliance. Nonetheless, the
Requirements set forth in TOP–002–1
are sufficiently clear and objective to
provide guidance for compliance.
978. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TOP–002–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–002–1 that: (1) Includes
Measures and Levels of Noncompliance; (2) deletes references to
confidentiality agreements in
Requirements R3 and R4, but addresses

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the issue separately to ensure that
necessary protections are in place
related to confidential information; and
(3) requires the next-day analysis for all
IROLs to identify and communicate
control actions to system operators that
can be implemented within 30 minutes
following a contingency to return the
system to a reliable operating state and
prevent cascading outages.
979. Regarding outages of multiple
elements caused by the failure of single
element, NERC comments that it will
review the Requirement R7 to ensure
that reserves can be deployed to meet its
disturbance control Reliability
Standard, BAL–002–0. However,
MidAmerican and MRO assert that any
effort to define single contingencies in
terms of multiple elements will result in
a significant decrease in available
transmission capability (ATC) and will,
therefore, have a negative impact on
competition in the wholesale market. As
discussed in the TPL Chapter, the
simulations used for either planning or
calculating available transmission
capability must be consistent with the
number of elements that will be
removed from service in the physical
system.
d. Planned Outage Coordination (TOP–
003–0)
i. NERC Proposal
980. TOP–003–0 requires
transmission operators, generator
operators and balancing authorities to
coordinate transmission and generator
maintenance schedules. Where a
conflict in maintenance schedule arises,
the reliability coordinator is authorized
to resolve the conflict.
ii. Staff Preliminary Assessment
981. TOP–003–0 requires that each
transmission provider must provide
outage information on transmission
lines and transformers greater than 100
kV and each generator operator must
provide outage information for
generators greater than 50 MW. The
Staff Preliminary Assessment observed
that these Requirements assume that
only systems greater than 100 kV or
generators above 50 MW will affect the
reliability of interconnected operations.
Staff stated that, although this
assumption may be true in most
instances, a justification should be
provided for the threshold of 100 kV for
transmission and 50 MW for generation
outages. Staff further stated that the loss
of transmission lines or transformers
less than 100 kV and generators less
than 50 MW may affect system stability
in load pockets or remote sections of the
grid depending upon system conditions.

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982. The Staff Preliminary
Assessment noted that, while a related
Reliability Standard, TOP–002–0,
requires the coordination of planned
outages on a current-day, next-day and
seasonal basis for normal operations
planning, TOP–003–0 only requires
next-day reporting for planned outages
and does not include longer range
planning. The Staff Preliminary
Assessment expressed the concern that
this gap may affect reliability because
proper assessment of the system and
coordination between generation and
transmission outages may not occur.
Moreover, the lack of information may
also have an impact on TTC/ATC
calculations. Staff also noted that the
Levels of Non-Compliance are based on
designating a process for providing
information, but they do not contain
requirements for the actual provision of
that information

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iii. Comments
983. NERC comments that the 100 kV
and 50 MW thresholds may need to be
reviewed over time. However, NERC
believes that the Commission should
approve TOP–003–0 as proposed
because transmission operators,
balancing authorities and reliability
coordinators should decide which
facilities to include in their operations
planning assessments.
984. Allegheny agrees that the 100 kV
and 50 MW thresholds may not be
appropriate in all situations. However,
Allegheny points out that transmission
operators and reliability coordinators
typically coordinate all planned outages
that may have a significant impact on
interconnected operations. Rather than
lowering the thresholds to include all
facilities, Allegheny suggests that
transmission operators and reliability
coordinators identify significant
facilities through system studies.
MidAmerican and MRO recommend
that the thresholds should not be
lowered because this will slow down
the coordination of outages for higher
voltage facilities and larger generators.
985. ISO/RTO Council believes that
any size or voltage threshold must be
justified based on its potential impact to
reliability. In addressing lower voltage
levels, ReliabilityFirst comments that
system operators typically evaluate and
monitor lower voltages levels to ensure
they do not impact the reliability of the
Bulk Electric System. However,
ReliabilityFirst believes that the
assessment and monitoring of these
lower voltage levels should be included
in the Reliability Standard for
uniformity and consistency.

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iv. Commission Proposal
986. The Commission notes that
outage information is important to both
reliable operation and to the calculation
of available transfer capability. This
information is also needed to assure
coordination of outages long before next
day or current day operations. The
Commission proposed that applicable
scheduled outages be communicated to
impacted transmission operators and
reliability coordinators with sufficient
lead time to coordinate outages. The
Commission requests industry input on
what constitutes sufficient lead time for
planned outages.
987. NERC, Allegheny, ISO/RTO
Council, and ReliabilityFirst agree with
the Staff Preliminary Assessment that
the thresholds for providing outage
information should be reviewed. While
we agree with commenters that lowering
the threshold might slow down the
coordination process, we are also
concerned that the thresholds of 100 kV
and 50 MW may not include all
facilities that have a significant impact
on the operation of Bulk-Power System.
For example, emergency operations
would require, at a minimum, that there
are adequate blackstart resources
available if needed. Thus, while in the
longer-term a review of the existing
thresholds is appropriate, at this time,
we propose directing NERC to modify
TOP–003–0, Requirement R1 to provide
that a generator operator or transmission
operator must provide planned outage
information for any facility above 100
kV and 50 MW and any other facility
below these thresholds that, in the
opinion of the transmission operator,
balancing authority, or reliability
coordinator, would have a direct impact
on the operation of Bulk-Power System.
988. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TOP–003–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–003–0 that: (1) Includes a
requirement to communicate scheduled
outages well in advance to ensure
reliability and accuracy of ATC
calculation; and (2) makes any facility
below the thresholds that, in the
opinion of the transmission operator,
balancing authority, or reliability
coordinator, will have a direct impact

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on the operation of Bulk-Power System
subject to Requirement R1 for planned
outage coordination.
e. Transmission Operations (TOP–004–
0)
i. NERC Proposal
989. TOP–004–0 requires
transmission operators to operate the
transmission system within SOL and
IROL. The ‘‘N–1’’ operating criterion for
the transmission system is also
established in this Reliability Standard.
It provides that operating configurations
for which limits have not yet been
determined should be treated as
emergencies. The reliability goal of
TOP–004–0 is to maintain Bulk-Power
System facilities within limits, thereby
protecting transmission, generation,
distribution and customer equipment
and preventing cascading failures of the
interconnected grid. Further, NERC
indicates that it plans to modify TOP–
004–0 to address the lack of Measures
and Levels of Non-Compliance.
ii. Staff Preliminary Assessment
990. The Staff Preliminary
Assessment noted that a regional review
of the potential impact of multiple
outages in day-ahead operations
planning is included in Requirement R3
for TOP–004–0. However, staff observed
that the conditions under which
multiple outages can occur remain
undefined.
991. The proposed Reliability
Standard requires the operation of the
system within IROL and SOL. When the
system enters an unknown state (i.e.,
any state for which operating limits
have not been determined),
Requirement R4 instructs the operator to
‘‘restore operations to respect proven
reliable power system limits within 30
minutes.’’ Staff cautioned that the
phrase ‘‘within 30 minutes’’ could be
interpreted as a grace period. However,
such an interpretation may not be
consistent with the intent that, while 30
minutes has been adopted by the
industry as a reasonable time period, it
is expected that corrective actions will
be taken as soon as possible and without
delay.
iii. Comments
992. NERC responds to the Staff
Preliminary Assessment, stating that the
specification of 30 minutes is not meant
to suggest that system operators should
take as long as 30 minutes. Rather, it is
meant to provide system operators with
the flexibility to respond to emergencies
in the manner they determine is best,
even if it is not the fastest alternative.
In addition, NERC asserts that: (1) 30
minutes is based on decades of system

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operations experience; (2) system
operators do not treat ‘‘within 30
minutes’’ as a grace period and it has
not come across situations when system
operators waited for 29 minutes before
taking an appropriate action; and (3)
although a system is not allowed to drift
in and out of a secure state, sometimes
it enters an unknown state that was not
studied and it is appropriate to allow
the system operators a reasonable
amount of time to bring the system back
to the normal state.
993. MidAmerican comments that, if
IROL cannot be exceeded even for one
minute, operators will need to maintain
a margin at significant cost and there
will be a resulting negative impact on
competition.

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iv. Commission Proposal
994. The Commission proposes to
approve TOP–004–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard as discussed
below.
995. Requirement R4 of TOP–004–0
provides that, if a transmission operator
enters an unknown state, i.e., any state
for which valid operating limits have
not been determined, operations should
be restored to respect proven reliable
power system limits within 30 minutes.
We agree with NERC that 30 minutes is
a reasonable period within which
operators should return the system to a
reliable operating state. However, as
stated in the Staff Preliminary
Assessment it may be interpreted as a
grace period to the detriment of
reliability and therefore the Commission
proposes that Requirement R4 be
modified to state that the system should
be restored to respect proven reliable
power system limits as soon as possible
and no longer than 30 minutes.
996. With respect to NERC’s comment
that the system is not allowed to drift in
and out of a reliable state, the
Commission is concerned that neither
TOP–004–0 nor the IRO Reliability
Standards address this issue and that
some entities may be engaging in this
practice to the detriment of reliability.
The Commission proposes to require
that NERC survey and report the
operating practices and actual
experiences surrounding drifting into
and out of IROL limits.305
997. The Staff Preliminary
Assessment noted that while
Requirement R3 states that, when
practical, the system must be operated
305 The issue of drifting in and out of IROL limits
is discussed in the IRO chapter and provides
specifics of proposed survey in greater detail. See
discussion for IRO–005–1.

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to respect multiple outages as specified
by the regional reliability organization
policy it does not define conditions
under which such multiple outages
must be considered. We interpret such
conditions to include high risk
conditions such as hurricanes, ice
storms or periods of high solar magnetic
disturbances during which the
probability of a multiple outage
approaches that of single element
outage. The Commission proposes that
Requirement R3 be modified to define
conditions under which the system
must be operated to respect multiple
outages.
998. The Commission notes that TOP–
004–0 does not contain Measures or
Levels of Non-Compliance. TOP–004–0
serves an important reliability goal of
ensuring that the Bulk-Power System
facilities are operated within safe limits,
thereby protecting transmission,
generation, distribution and customer
equipment and preventing cascading
failures. The Commission believes that
it is important for NERC to provide
Measures and Levels of NonCompliance elements for this proposed
Reliability Standard. Nonetheless, the
proposed Requirements set forth in
TOP–004–0 are sufficiently clear and
objective to provide guidance for
compliance.
999. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TOP–004–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–004–0 that (1) includes
Measures and Levels of NonCompliance; (2) clarifies that the 30
minute response time is not a grace
period; and (3) defines in Requirement
R3, high risk conditions under which
the system must be operated to respect
multiple outages. In addition, we
propose to direct that the ERO perform
a survey of the prevailing operating
practices and actual operating
experiences surrounding drifting in and
out of IROL limits. As part of the survey,
we would require all reliability
coordinators to report any violations of
IROLs, their causes, the date and time
of the violation, and the duration in
which actual operations exceeded IROL
to the ERO on a monthly basis for one
year beginning two months after the
effective date of the final rule.

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f. Operational Reliability Information
(TOP–005–1)
i. NERC Proposal
1000. TOP–005–1 ensures that
reliability information is shared among
reliability coordinators, transmission
operators and balancing authorities.306
It requires the transmission operator and
the balancing authority to provide
operating data to each other and to the
reliability coordinator and provides a
list of typical operating data that must
be provided. TOP–005–1 also provides
that, as a condition of receiving data
from the NERC’s Interregional Security
Network,307 each data recipient must
execute a confidentiality agreement.
ii. Staff Preliminary Assessment
1001. Staff noted that Attachment 1 of
TOP–005–1 entitled, ‘‘Electric System
Reliability Data,’’ which specifies the
types of operating data that reliability
coordinators, balancing authorities and
transmission operators are expected to
share, does not include the operational
status of special protection systems and
power system stabilizers. The Staff
Preliminary Assessment raised the
concern that the absence of this
information could lead to an erroneous
assessment of system capability.
iii. Comments
1002. NERC agrees with Commission
Staff that Attachment 1 of TOP–005–1
should be modified to include special
protection systems and power system
stabilizers.
1003. ReliabilityFirst states that
information pertaining to the special
protection systems is included in
Attachment 1, section 2.6, which refers
to ‘‘new or degraded special protection
systems.’’
1004. ISO/RTO Council argues that
the Commission should direct NERC to
eliminate the requirement that each data
recipient sign a confidentiality
agreement. It claims that the
requirement to sign a confidentiality
agreement is an administrative matter,
not a reliability issue.
iv. Commission Proposal
1005. ReliabilityFirst points out that
the operational information pertaining
to the ‘‘new or degraded special
protection systems’’ is included in
Attachment 1. However, a special
306 NERC states that, effective November 1, 2006,
proposed Reliability Standard TOP–005–1 will
replace existing Reliability Standard, TOP–005–0.
307 Interregional Security Network is a data
exchange system that facilitates the exchange of
real-time and other operational data among
reliability coordinators, balancing authorities, and
transmission operators to help ensure reliable
electric power system operations.

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protection system may be turned on or
off and not be degraded. Awareness of
the operational state is different from
knowing that degradation has occurred.
In addition, Attachment 1 does not
contain information about power system
stabilizers. While Attachment 1 contains
a large amount of data pertaining to
Bulk-Power System reliability, inclusion
of information about the operation
status of special protection systems will
provide a more comprehensive list. We
agree with NERC and propose that
Attachment 1 be modified to include the
status of special protection systems and
power system stabilizers.
1006. We agree with ISO/RTO
Council that the reference to execution
of confidentiality agreement should be
deleted from the Reliability Standard
and NERC should address the issue
separately and globally as we indicate
above in our discussion of TOP–002–1.
1007. TOP–005–1 furthers an
important reliability goal of ensuring
that reliability entities have the
operating data needed to monitor
system conditions within their area.
Further, the Requirements set forth in
TOP–005–1 are sufficiently clear and
objective to provide guidance for
compliance. Accordingly, giving due
weight to the technical expertise of the
ERO and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TOP–005–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–005–1 that: (1) Includes
information about the operational status
of special protection systems and power
system stabilizers in Attachment 1; and
(2) deletes references to confidentiality
agreements, but addresses the issue
separately to ensure that necessary
protections are in place related to
confidential information.
g. Monitoring System Conditions (TOP–
006–0)

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i. NERC Proposal
1008. TOP–006–0 requires that
operating personnel continuously
monitor essential Bulk-Power System
parameters such as line flows, circuit
breaker status, generator resources,
relays, weather forecasts and frequency
to ensure that the facilities do not
exceed their operating limits. NERC
indicates that it plans to modify TOP–

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006–0 to address the lack of Measures
and Levels of Non-Compliance.
ii. Staff Preliminary Assessment
1009. The Staff Preliminary
Assessment noted that, while TOP–006–
0 identifies data requirements it does
not identify any minimum acceptable
tools and capabilities to turn the data
into information to aid in situational
awareness. Staff explained that
reliability coordinators, transmission
operators and balancing authorities
must be aware of the status of their
respective systems, and such situational
awareness cannot be obtained by
viewing massive amounts of raw data.
iii. Comments
1010. NERC agrees with the Staff
Preliminary Assessment that situational
awareness is ‘‘key’’ to operating an
interconnected electric system reliably
and that data collection is only one
component of a successful situational
awareness strategy. NERC, however,
states that whether a Reliability
Standard should specify how data
should be analyzed and presented to the
system operator or reliability
coordinator requires further discussion,
including discussions with vendors who
supply situational awareness and
visualization tools.
1011. ReliabilityFirst comments that
due to the variety of equipment used to
manage the Bulk-Electric System, it is
impractical to specify the type of
software and processes acceptable for
monitoring.
1012. MRO states that Requirement
R3, which requires an applicable entity
to provide ‘‘appropriate technical
information’’ concerning protective
relays, should be revised to clarify the
phrase, ‘‘appropriate technical
information.’’
iv. Commission Proposal
1013. The Commission proposes to
approve TOP–006–0 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
1014. The Blackout Report states that
‘‘a principal cause of the blackout was
a lack of situational awareness, which
was in turn a result of inadequate tools
and back-up capabilities.’’ 308 In
addition, in reviewing common factors
between the August 2003 blackout and
other major outages the Blackout Report
states ‘‘power system data may be
available but not be presented to
operators or coordinators as information
they can use in making appropriate
308 See

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decisions.’’ 309 While TOP–006–0
requires that a significant amount of
data be provided to operating personnel,
we agree with NERC that this is only
one component of a successful
situational awareness strategy. The data
must be converted into information that
operators can use to assess the state of
the system and its vulnerability, should
a contingency occur, and take
appropriate actions to maintain a
reliable system. We note that the
Requirement R7 of Reliability Standard
IRO–002–0 requires that reliability
coordinators have adequate tools such
as state estimation, pre and post
contingency analysis capabilities and
wide area overview displays. We believe
that similar tools should be made
available to transmission providers and
balancing authorities and propose that
the ERO add a new Requirement in this
Reliability Standard to provide adequate
tools to transmission operators and
balancing authorities, which will
provide them situational awareness.
1015. Although we agree with NERC
that further discussions may be needed
with vendors who supply situational
awareness and visualization tools,
modification of TOP–006–0 should not
have to wait for those discussions to
occur. A variety of off-the-shelf tools are
currently available from vendors and in
use across the industry. At a
Commission sponsored technical
conference on July 14, 2004, staff
presented its views on minimum
requirements and best practices for
reliability tools for the purpose of
initiating discussions on what these
minimum reliability capabilities ought
to be. We believe that identification of
the types of tools and what they should
minimally accomplish would improve
the proposed Reliability Standard.
Entities that must comply with TOP–
006–0 could choose among the available
software tools that accomplish the
desired goal or meet the Requirement
set forth in the Reliability Standard.
Accordingly, we propose to direct NERC
to modify TOP–006–0 to include a
requirement for a minimum set of tools
for transmission operators and
balancing authorities that will aid in
situational awareness.
1016. We agree with MRO that the
phrase ‘‘appropriate technical
information’’ is open to interpretation
and propose to direct that NERC modify
TOP–006–0, Requirement R3, to identify
the specific type of technical
information concerning protective
relays that should be provided.
1017. TOP–006–0 serves an important
reliability goal of requiring monitoring
309 Id.

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of essential Bulk-Power System
parameters such as the status of power
system elements, real and reactive
power flows, voltages and frequency to
ensure that the system and its
equipment are operated in a reliable and
safe manner. The Commission believes
that it is important for NERC to provide
Measures and Levels of Non-compliance
for this proposed Reliability Standard.
Nonetheless, the proposed
Requirements set forth in TOP–006–0
are sufficiently clear and objective to
provide guidance for compliance.
1018. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO, and that it will improve the
reliability of the nation’s Bulk-Power
System the Commission proposes to
approve Reliability Standard TOP–006–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–006–0 that: (1) Includes
Measures and Levels of Non-compliance
elements; (2) includes a new
requirement related to the provision of
a minimum set of analysis tools that
will aid in situational awareness; and
(3) clarifies the meaning of ‘‘appropriate
technical information’’ concerning
protective relays.
h. Reporting SOL and IROL Violations
(TOP–007–0)
i. NERC Proposal
1019. TOP–007–0 requires that
violations of SOL and IROL are
promptly reported to the reliability
coordinator so that it can direct
corrective action and inform other
affected systems. It also requires a
transmission operator to mitigate an
IROL violation as soon as possible but
no longer than 30 minutes. A
transmission operator must take ‘‘all
appropriate actions up to and including
shedding firm load’’ to return its system
to a stable state within IROL. Finally, it
requires that the reliability coordinator
take action to mitigate an SOL or IROL
violation if the transmission operator’s
actions are not effective.

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ii. Staff Preliminary Assessment
1020. As indicated above, TOP–007–
0 requires that, ‘‘[f]ollowing a
[c]ontingency or other event that results
in an IROL violation, the transmission
operator shall return its transmission
system to within IROL as soon as
possible, but not longer than 30

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minutes.’’310 The Staff Preliminary
Assessment explained that the phrase
‘‘or other event’’ in this Requirement is
open to interpretation. One
interpretation is that it allows IROLs to
be exceeded under normal precontingency conditions, provided the
system can be returned to a secure state
within 30 minutes. Another, more
conservative, interpretation is that the
Requirement does not allow IROLs to be
exceeded under normal pre-contingency
conditions, and that after a contingency
occurs the system must be returned to
a secure condition as soon as possible
and no later than 30 minutes. The Staff
Preliminary Assessment cautioned that,
if the system is operated in a less
conservative manner during the period
where IROL is exceeded, even a single
system contingency could cause
instability, uncontrolled separation, and
even a cascading blackout.
iii. Comments
1021. NERC states that SOL and IROL
need better definition, also noting that
SOL and IROL are operating states that
system operators must move away from
as quickly as possible. It will consider
revising the standard to clarify that a
contingency is not required to violate
the SOL and IROL limits. NERC notes
that it has commissioned an Operating
Limit Definition Task Force to work on
this matter and the Task Force is
expected to submit its recommendation
by the end of 2006.
1022. Also seeking more definition
and detail on SOL and IROL,
ReliabilityFirst urges the acceleration of
standards now being developed to
clarify SOL and IROL. However, it adds
that it would be impractical to identify
and study all possibilities for alleviating
SOL and IROL.
1023. ISO/RTO Council agrees with
the Staff Preliminary Assessment that
this Reliability Standard is open to
interpretation. However, ISO/RTO
Council states that it is appropriate to
give system operators discretion in
making real-time system operating
decisions. It comments that a more
prescriptive standard would unduly
restrict system operators and the nature
of real-time operations requires giving
these entities some leeway. Thus, the
ISO/RTO Council recommends that the
Commission approve TOP–007–0 in its
present form.
1024. MRO recommends that an IROL
violation exceeding 30 minutes be
reported to NERC within 48 hours rather
than the 72 hours allowed under the
310 Reliability

Standard TOP–007–0, Requirement

R2.

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compliance section of this Reliability
Standard.
iv. Commission Proposal
1025. As noted in our discussion in
IRO–005 and TOP–004, the Commission
is concerned about systems drifting in
and out of SOL and IROL violations.
One source of justification for that
practice is the term ‘‘other event.’’ We
agree with NERC that SOL and IROL
need better definitions and TOP–007–0
could be improved by making the
requirements clearer. Our proposal for a
survey in IRO–005 and TOP–004 to
collect data will give us more
information about the extent of the
problem with regard to drifting in and
out of SOL and IROL violations.
1026. Regarding MRO’s
recommendation that IROL violations
exceeding 30 minutes be reported to
NERC within 48 hours, we will leave
this determination to NERC because we
consider this to be a matter of
administrative convenience.
1027. TOP–007–0 serves an important
reliability goal of ensuring that when
critical limits are violated, the violations
are reported and appropriate actions
taken to avoid any cascading outages.
The Commission believes that it is
important that NERC address the
ambiguity regarding IROL violations,
discussed above. Nonetheless, the
proposed Requirements set forth in
TOP–007–0 are sufficiently clear and
objective to provide guidance for
compliance.
1028. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission believes that
Reliability Standard TOP–007–0 is just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest; and proposes to approve it as
mandatory and enforceable.
1029. The Commission solicits
comment on potentially overlapping
matters addressed in Reliability
Standards TOP–007–0 and TOP–008–0.
The title and the purpose of TOP–007–
0 state that it ensures that SOL and
IROL violations are being reported, but
we believe that only Requirement R1
relates to reporting. The remaining
requirements in TOP–007–0, R2, R3 and
R4, go beyond reporting of violations
and provide that the transmission
operator will take actions on its own or
as directed by the reliability
coordinator. We observe that proposed
Reliability Standard TOP–008–0
addresses the same subject. In fact,

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Requirement R1 of TOP–008–0 is
similar to Requirement R3 of TOP–007–
0. It appears that both Reliability
Standards deal with the same subject,
but more emphasis is placed on
reporting in TOP–007–0. If two separate
Reliability Standards address similar
topics, the purpose statement should
succinctly capture the intent of each
Reliability Standard.
i. Response to Transmission Limit
Violations (TOP–008–0)
i. NERC Proposal
1030. TOP–008–0 requires a
transmission owner to take immediate
steps to mitigate SOL and IROL
violations. NERC indicates that it plans
to modify TOP–008–0 to address the
lack of Measures and Levels of NonCompliance.
ii. Staff Preliminary Assessment
1031. The Staff Preliminary
Assessment did not identify any
substantive issues in TOP–008–0, other
than noting that it does not contain
Measures or Levels of Non-Compliance.

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iii. Comments
1032. No comments were submitted
regarding TOP–008–0.
iv. Commission Proposal
1033. We observe that proposed
Reliability Standard TOP–007–0
addresses the same subject.
1034. Requirements R1 through R4
provide that the transmission operator
shall take certain actions to mitigate the
effects of SOL and IROL violations. No
role is specified for the reliability
coordinator. A reliability coordinator
plays a key role in the reliability of the
Bulk-Power Systems and should be
involved in the decision-making process
of bringing the system back within
operating limits as soon as possible. A
parallel Reliability Standard covering
this subject, TOP–007–0, identifies a
role for the reliability coordinator. The
Commission proposes to require NERC
to modify TOP–008–0 to apply to
reliability coordinators.
1035. TOP–008–0 serves an important
reliability goal of ensuring that when
critical limits are violated, appropriate
actions are taken to avoid any cascading
outages. The Commission believes that
it is important for NERC to provide
Measures and Levels of non-compliance
elements for this proposed Reliability
Standard. Nonetheless, the proposed
Requirements set forth in TOP–008–0
are sufficiently clear and objective to
provide guidance for compliance.
1036. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the

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Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TOP–008–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TOP–008–0 that: (1) includes
Measures and Levels of Non-compliance
elements; and (2) includes reliability
coordinators in the Applicability
section.
12. TPL: Transmission Planning
a. Overview
1037. The Transmission Planning
(TPL) group of Reliability Standards
consists of six Reliability Standards that
are applicable to transmission planners,
planning authorities and regional
reliability organizations. These
Reliability Standards are intended to
ensure that the transmission system is
planned and designed to meet an
appropriate and specific set of reliability
criteria. Transmission planning is a
process that involves a number of stages
including developing a model of the
Bulk-Power System, using this model to
assess the performance of the system for
a range of operating conditions and
contingencies, determining those
operating conditions and contingencies
that have an undesirable reliability
impact, identifying the nature and the
need for transmission upgrades,
developing and evaluating a range of
transmission reinforcement and upgrade
options and selecting the preferred
option, taking into account the time
needed to place the facilities in service.
The proposed TPL Reliability Standards
address: (1) the types of simulations and
assessments that must be performed to
ensure that reliable systems are
developed to meet present and future
system needs 311 and (2) the information
required to assess regional compliance
with planning criteria and for selfassessment of regional reliability.312 The
differing definitions of the Bulk-Power
System and bulk electric system
discussed above is central to the
concerns raised by this group of
Reliability Standards.313 That issue has
important implications for the range of
contingencies that must be evaluated
311 See TPL–001–0, TPL–002–0, TPL–003–0, and
TPL–004–0.
312 See TPL–005–0 and TPL–006–0.
313 See discussion of Bulk Power System v. bulk
electric system in section III.D.5 above.

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and facilities to be simulated in the
transmission planning process.
1038. The TPL group of Reliability
Standards contains a table designated
Table 1 (Transmission System
Standards—Normal and Emergency
Conditions), which is a key part of this
group of Reliability Standards. It lays
out the system performance
requirements for a range of
contingencies grouped according to the
number of elements forced out of
service as a result of the contingency.
For example: Category A applies to the
normal system with no contingencies;
Category B applies to contingencies
resulting in the loss of a single element
defined as a generator, transmission
circuit, transformer, single DC pole with
or without a fault; Category C applies to
a contingency resulting in loss of two or
more elements, such as any two circuits
on a multiple circuit tower line or both
poles of a bi-polar DC line; while
Category D applies to extreme
contingencies resulting in loss of
multiple elements, such as a substation
or all lines on a right-of-way. The
system performance expectations for
Category C contingencies are lower than
those for Category B contingencies, in
that they allow unspecified amounts of
planned or controlled loss of demand.
b. General Issues
1039. Both the Staff Preliminary
Assessment and commenters raise a
number of issues that apply generally to
Reliability Standards TPL–001–0
through TPL–004–0. We address these
issues here and, in addition, apply our
general discussion when addressing
each individual Reliability Standard.
i. Staff Preliminary Assessment
1040. Staff stated that, in general, the
TPL Reliability Standards raise issues
regarding requirements that are
ambiguous, and ‘‘limited sets of
contingencies,’’ i.e, they do not address
outages of multiple-elements resulting
from some probable single events and
critical system conditions.314
1041. NERC responds that, while the
proposed Reliability Standards need
review and incremental improvement,
staff’s criticisms of the TPL group of
Reliability Standards are overstated.
Likewise, EEI believes that the TPL
group of proposed Reliability Standards
is technically sound and sufficiently
detailed. NERC contends that the
purpose of Reliability Standards is not
to make the Bulk-Power System failureproof, but to ensure it is able to meet
specific performance requirements
under normal conditions and following
314 Staff

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single contingencies and certain
credible multiple-contingencies. The
TPL standards require assessment of
multiple-contingency and extreme
contingency events but do not require
that the system be able to withstand
such events without loss of firm load
and, according to NERC, requiring this
would be impractical and extremely
costly.
1042. The Commission agrees with
NERC that the Reliability Standards are
not intended to make the Bulk-Power
System failure-proof. Nor do we propose
to modify the TPL Reliability Standards
to require that the system be able to
withstand all multiple-contingency and
extreme contingency events without
loss of load. Nonetheless, we believe
that the planning-related Reliability
Standards could be improved to better
take into account probable
contingencies when planning studies
are conducted. Much of our proposal is
consistent with the possible means of
improvement recognized by NERC in its
comments responding to the Staff
Preliminary Assessment. Further, we
note that a number of regions currently
utilize superior planning practices that
may be characterized as ‘‘best practices’’
and are more stringent than the
proposed TPL Reliability Standards.315
Accordingly, we propose that the ERO
submit to the Commission such regional
differences in transmission planning
criteria that are more stringent than
those specified in the TPL group of
Reliability Standards.
ii. Stressing the System During
Simulations
1043. Staff stated that, when carrying
out power systems simulations it is
important to ensure that the system
under study is sufficiently stressed so
that any underlying weaknesses or
deficiencies can be identified and to test
the performance of the system under
study for a wide variety of probable
scenarios. It suggested that such
simulations ‘‘would determine the most
onerous sets of system conditions
* * *’’ 316 Staff stated that system
conditions are as important as
contingencies in evaluating the
performance of present and future
systems, but that the Reliability
Standards do not require that sensitivity
studies be carried out or specify the
315 Examples include practices cited in NERC’s
‘‘Examples of Excellence’’ found in its Readiness
Audits, filings for jurisdictional utilities in Part 4
of FERC Form No. 715, Transmission Planning
Reliability Criteria. Regional Reliability
Organizations also specify requirements that exceed
NERC Reliability Standards, such as WECC’s
Minimum Operating Requirement Criteria and the
NPCC Document A–02—Basic Criteria for Design
and Operation of Interconnected Power Systems.
316 Staff Preliminary Assessment at 109.

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rationale for determining critical system
conditions and study years.
1044. A number of commenters
reacted strongly to staff’s suggestion
regarding the use of simulations to
determine ‘‘the most onerous sets of
system conditions.’’ CenterPoint states
that planning for the most onerous set
of conditions would have an
unreasonable impact on transmission
rates and the need for new transmission
lines.
1045. MRO and MidAmerican support
clarifying ambiguities but prefer that
Reliability Standards not become overly
prescriptive in a way that would restrict
engineering judgment. For example,
MRO comments that sensitivity studies
should be performed as part of the
planning process, but it recommends
that the planning entity develop the
system conditions, planning years, and
other aspects of the sensitivity
scenarios. ReliabilityFirst adds that
defining a checklist for planning would
encourage planners to rely on the
checklist to the exclusion of good
engineering judgment.
1046. The TPL Reliability Standards
require Transmission Planners and
Planning Authorities to conduct system
performance assessments. Such
assessments must address specific
topics, including ‘‘critical system
conditions and study years as deemed
appropriate by the entity performing the
study.’’ 317 As noted by staff and
commenters,318 system conditions are as
important as contingencies in evaluating
the performance of present and future
systems. The Commission is concerned
that this Requirement allows complete
discretion to the entity performing the
study and does not provide any
parameters or criteria for such an entity
to determine critical system conditions
and study years in a rational and
consistent manner.
1047. With regard to CenterPoint’s
comment, we agree that it is not realistic
to expect the ERO to develop a
Reliability Standard that anticipates
every conceivable critical operating
condition applicable to unknown future
configurations for regions with various
configurations and operating
characteristics. The practical solution
that has been implemented by many in
the industry is to perform sensitivity
studies that define and provide
documentation of the impact on the
system. For that reason, we believe that
it would be appropriate for planning
317 E.g., Reliability Standard TPL–001–0,
Requirement R1.3.
318 See Staff Preliminary Assessment at 109. See
also CenterPoint, MidAmerican and MRO
comments.

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entities to conduct sensitivity studies to
‘‘bracket’’ the range of probable
outcomes. Thus, without having to
anticipate ‘‘every conceivable critical
operating condition,’’ planning entities
will have a means to identify an
appropriate range of critical operating
conditions. While Requirement R1.3
identifies firm transfers, selected
demand levels, existing and planned
facilities, reactive power resources, and
control devices, a sensitivity study to
determine critical system conditions
should consider such additional matters
as the range of load power factors,
generation retirements, generation
dispatch and transaction patterns,
controllable loads and DSM at specific
locations, and transmission outages,
including outages of reactive power
devices. The Commission is not
precluding other approaches to define
and document critical system
conditions that have been proven to be
effective.319 We propose that the ERO
modify the relevant TPL Reliability
Standards accordingly. Further we
propose that the results of these studies
be documented to support the selection
of critical system conditions used in
assessing system performance.
iii. Element-Based vs. Event-Based
Contingencies
1048. As explained in the TPL
overview above, Table 1 of the TPL
Standards lays out the system
performance requirements for a range of
contingencies grouped according to the
number of elements forced out of
service as a result of the contingency.
The Staff Preliminary Assessment
explained that the single unanticipated
failure of some elements in the BulkPower System can result in the loss of
multiple elements. Because of the
resulting impact on reliability, some
regions base their groupings according
to the event irrespective of the number
of elements forced out of service (as
opposed to categorizing contingencies
according to elements forced out of
service). For such a region, a single
event that results in the loss of multiple
elements, e.g., a lightning strike, that
simultaneously forces out of service
both circuits of a double circuit tower
line, is considered a single contingency
similar to the loss of a single element
such as a generator. What is acceptable
in one region may not be acceptable in
another region because of historical
adoption of reliability criteria rather
than physical differences in systems.
319 While contingencies have been defined in
Table I, the Commission does not believe systems
conditions lend themselves to a table or a simple
list.

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1049. Most commenters that address
this topic oppose an event-based
contingency planning approach on the
grounds that it is difficult to perform,
too conservative, too costly to the
public, too rigid, or not based on the
probabilities of outages occurring in the
real system.320 National Grid, on the
other hand, supports event-based
contingency planning on the contention
that it provides a more robust analysis.
The Commission believes that planning
standards must influence system design
and not the other way around. To
achieve this objective, planning
standards should promote system
designs that result in the minimum set
of elements being removed from service
for ‘‘unanticipated failures of system
elements.’’ 321 The Commission notes
that entities with planning
responsibility for approximately half of
the load in the nation analyze
contingencies based on the actual
number of elements that would be
removed from service in the actual
power system for an unanticipated
failure of system elements, rather than
simulating only the outages identified in
Table 1. Simply put, the Commission
believes that the simulations should
faithfully duplicate what will happen in
the actual power system and not a
generic listing of outages.
1050. In addition, the Bulk-Power
System must be operated and planned
to be operated within a number of
conditions after a contingency or cyber
event. The Contingency can be a sudden
disturbance or unanticipated failure of
any system element. If a specific portion
of the system has been designed such
that the response to a failure results in
multiple lines, transformers, generators,
circuit breakers, etc., being removed
from service, then the Commission
proposes that this is what should be
simulated.
1051. Planning for Cybersecurity
incidents have not been part of the
traditional planning study process. One
approach is to identify specific
vulnerabilities based on the designs at
specific locations and then study the
impact of those vulnerabilities. The
Commission is interested in comments
from industry on this subject such as
whether planning for cybersecurity
events should be addressed in the
320 See, e.g., CenterPoint, EEIm Mid American,
New York Commission and ReliabilityFirst.
321 Section 215(a) of the FPA defines ‘‘Reliable
Operation’’ as ‘‘means’’ operating the elements of
the Bulk-Power System within equipment and
electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or
cascading failures of such system will not occur as
a result of sudden disturbance, including a
Cybersecurity Incident, or unanticipated fialure of
system elements’’ (emphasis added).

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planning standards or in the CIP
standards.
c. System Performance Under Normal
(No Contingency) Conditions (TPL–001–
0)
i. NERC Proposal
1052. Proposed Reliability Standard
TPL–001–0 deals with planning relevant
to system performance under normal
conditions, i.e., a situation where no
system contingency or no unexpected
failure or outage of a system component
has occurred.322 NERC states in its
application that the proposed Reliability
Standard ensures that the Bulk-Power
System is planned to meet the system
performance requirements under these
normal conditions by requiring the
transmission planner and the planning
authority to evaluate their transmission
system annually and document the
ability of that system to meet the
performance requirements established
in the Reliability Standard under
conditions where no system
contingencies are present.323 Meeting
these requirements means two things.
First, when all system facilities are in
service and normal operating
procedures are in effect, the system can
be operated to supply projected
customer demands and projected firm
(non-recallable reserved) transmission
services at all demand levels over the
range of forecast system demands.
Secondly, the system remains stable and
within the applicable ratings for thermal
and voltage limits, no loss of demand or
curtailed firm transfers occurs, and no
cascading outages occur. TPL–001–0
applies both to near-term and longerterm planning horizons.
1053. The Requirements of TPL–001–
0 specify that the planning authority
and transmission planner must
demonstrate through a valid assessment
that the Reliability Standard’s system
performance requirements can be met.
The assessment must be supported by a
current or past study and/or system
simulation testing that addresses
various categories of conditions to be
simulated as set forth in the Reliability
Standard to verify system performance
under normal conditions. When system
simulations indicate that the system
cannot meet the performance
requirements stipulated in the
Reliability Standard, a documented plan
to achieve system performance
requirements must be prepared. The
322 The NERC glossay defines a ‘‘contingency’’ as
‘‘[t]he unexpected failure or outage of a system
component, such as a generator, transmission line,
circuit breaker, switch or other electrical element.’’
NERC glossary at 3.
323 The performance requirements are set forth in
Category A of Table I of the standard.

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specific study elements selected from
each of the categories for assessments
are subject to approval by the associated
regional reliability organization.
ii. Staff Preliminary Assessment
1054. The Staff Preliminary
Assessment explained that TPL–001–0
does not require the consideration of
planned outages, which are a common
occurrence, in assessing system
performance. Staff also stated that the
Reliability Standard does not require
sensitivity studies to define critical
conditions and that footnote (a) to Table
1—which states in part that ‘‘Applicable
Ratings may include Emergency Ratings
applicable for short durations as
required to permit operating steps
necessary to maintain system control’’
and therefore only pertains to
contingency conditions—should be
clarified that it is only applicable to
Categories B, C, and D, i.e., situations
involving system contingencies or
failures of system components.
1055. Staff noted that the purpose
statement for this Reliability Standard is
identical to those for TPL–002, TPL–003
and TPL–004 although the goal and
requirements are different. The
transmission planning Reliability
Standards TPL–001–0 through TPL–
004–0 define various categories of
conditions to be simulated. Staff noted
that Requirement R1.3 in each of these
Reliability Standards allows fewer than
the specific study elements identified in
Table 1 to be selected from each of the
categories for assessments with the
approval by the associated regional
reliability organization, even though
selection of fewer elements may impact
neighboring systems.
iii. Comments
1056. MRO comments that the
Requirements of TPL–001–0 need
clarification because it is not clear as to
what is required. In addition, it asserts
that staff appears to indicate that Order
No. 2003 and TPL–001–0 have separate
requirements which must be followed.
To avoid the creation of dual Reliability
Standards, MRO maintains that the
Commission should explain how the
Requirements of this Reliability
Standard relate to the requirements of
Order No. 2003 and clarify that entities
will only be required to comply with a
single set of reliability requirements.
1057. ReliabilityFirst disagrees that
footnote (a) to Table 1 is ambiguous. It
states that emergency ratings are not
applicable when all facilities are in
service.
1058. ISO/RTO Council comments
that Requirement 1 of TPL–001–0
should define more clearly which entity

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is classified as a ‘‘planning authority.’’
It also recommends that because the
planning authority only has authority to
plan for system expansion, the word
‘‘consider’’ used in Requirement R2 in
connection with lead times necessary
for implementation should be changed
to ‘‘estimate.’’

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iv. Commission Proposal
1059. The Commission proposes to
approve TPL–001–0 as a mandatory and
enforceable Reliability Standard. In
addition, we propose to direct that
NERC develop modifications to the
Reliability Standard, as discussed
below.
1060. Transmission Planning requires
information on forecasted loads and
probable generation plans to supply
those loads. While information on
forecasted loads, energy, interruptible
loads and direct control load
management over the next ten years are
required to be made available by the
MOD Reliability Standards, there is no
requirement to inform transmission
planners and planning authorities of
new or retiring generation resources. We
seek comments on whether transmission
planners and planning authorities are
currently able to obtain and validate
resource information on new generation
and retirements for assessments over the
ten year planning horizon. If
transmission planners and planning
authorities currently experience
difficulty obtaining this information,
how should this potential information
gap be addressed?
1061. In assessing system
performance, TPL–001–0 requires
entities to cover ‘‘critical system
conditions and study years,’’ as deemed
appropriate by the entity performing the
study. As discussed above regarding
Stressing the System During
Simulations, the Reliability Standard
does not specify the rationale for
determining critical system conditions
and study years. Consistent with our
discussion of this issue above, the
Commission proposes that the ERO
modify TPL–001–0 to require that
critical system conditions be
determined by conducting sensitivity
studies covering such factors as load
power factors, different likely
generation expansion scenarios
including generation retirements,
alternative generation dispatch and
transaction patterns, controllable loads
and DSM at specific locations, and
transmission outages, including outages
of reactive power devices. The
Commission would expect that the
results of these studies would be used
to document the selection of critical

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system conditions and study years used
in assessing system performance.324
1062. The Commission notes that load
models used in system studies have a
significant impact on system
performance, particularly as they relate
to the dynamic performance of the
system. The Commission proposes that
the Reliability Standard be modified to
require documentation of load models
used in system studies and supporting
rationale for their use.
1063. Requirement R1.3 of TPL–001–
0 provides that the Planning Authority
and Transmission Planner must provide
studies and system simulations to
support its planning assessment, and
that the ‘‘specific elements selected [for
the study] shall be acceptable to the
associated Regional Reliability
Organization(s).’’ As we have discussed
elsewhere, the Commission believes that
the regional reliability organization
should not have such a role in the
context of mandatory Reliability
Standards. Rather, the ERO or the
appropriate Regional Entity(s) should
provide this oversight. Also, given that
neighboring systems may be adversely
impacted, the Commission proposes
that the neighboring systems be
involved in the determination and
review of system conditions and
contingencies to be assessed.
1064. As mentioned above, staff noted
that TPL–001–0 does not require the
consideration of planned outages. While
Reliability First agrees with staff,
CenterPoint disagrees because operators
schedule planned outages at times when
the reliability risk is minimized.
Planned outages are an every day
occurrence that, if excluded, would not
provide an accurate assessment of
system conditions. Accordingly, the
Commission proposes to direct that
NERC modify TPL–001–0 to require
consideration of planned outages of
critical equipment. We note that TPL–
002–0 through TPL–004–0 require
consideration of planned outages.
1065. NERC and other commenters
agree with staff that footnote (a) to Table
1 requires clarification. The NERC
Transmission Issues Subcommittee
(TIS) 325 recommended that footnote (a)
324 The Commission expects that the results of the
sensitivity studies taken together would form the
basis for evaluating adherence to criteria, i.e.,
adhering to system performance expectations
following contingencies specified in Table 1.
Failure of one sensitivity study of a very low
probability simulation would not, by itself, warrant
the need for mitigation plans. However, if the
simulations, taken as a whole, show miltiple areas
of weaknesses or criteria violations, then mitigation
plans would be required.
325 NERC Transmission Issues Subcommittee,
Evaluation of Criteria, Methods, and Practices Used
for System Design, Planning and Analysis in

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be modified to state explicitly that
emergency ratings apply to Category B
and C (contingency conditions) and not
to Category A (system intact). The
Commission proposes that footnote (a)
be modified in the revised Reliability
Standard as recommended by TIS and
that the normal facility rating be in
accordance with Reliability Standard
FAC–008–1 and normal voltages be in
accordance with Reliability Standard
VAR–001–1.
1066. While the Commission has
identified a number of concerns with
regard to TPL–001–0, this proposed
Reliability Standard serves an important
purpose by ensuring the Bulk-Power
System is planned to meet the system
performance requirements under normal
conditions. Further, the Requirements
set forth in TPL–001–0 are sufficiently
clear and objective to provide guidance
for compliance.
1067. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TPL–001–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TPL–001–0 that: (1) Requires that
critical system conditions be
determined by conducting sensitivity
studies; (2) requires that system
conditions and contingencies assessed
be reviewed by neighboring systems; (3)
modifies Requirement R1.3 to substitute
the reference to regional reliability
organization with Regional Entity; (4)
requires consideration of planned
outages of critical equipment; and (5)
modifies footnote (a) as discussed
above.
d. System Performance Following Loss
of a Single Element (TPL–002–0)
i. NERC Proposal
1068. Proposed Reliability Standard
TPL–002–0 concerns planning system
relevant to performance under
contingency conditions involving the
failure of a single element with or
without a fault, i.e., the occurrence of an
event such as a short circuit, a broken
wire or an intermittent connection.
NERC states that the Reliability
Standard ensures that the future BulkPower System is planned to meet the
system performance requirements of a
Response to NERC Blackout Recommendation 13c
(Nov. 28, 2005) (NERC TIS Report) at 15.

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system, with the loss of one element, by
requiring that the transmission planner
and planning authority annually
evaluate and document the ability of the
transmission system to meet the
performance requirements where an
event results in the loss of a single
element.326 Meeting these requirements
means two things. First, the system can
be operated following the event to
supply projected firm customer
demands and projected firm (nonrecallable reserved) transmission
services at all demand levels over the
range of forecast system demands.
Second, the system remains stable and
within the applicable ratings for thermal
and voltage limits, no loss of demand or
curtailed firm transfers occurs, and no
cascading outages occur. The Reliability
Standard applies both to near-term and
longer-term planning horizons.
1069. TPL–002–0 specifies that the
planning authority and transmission
planner must demonstrate through a
valid assessment that the standard’s
system performance requirements can
be met. The assessment must be
supported by a current or past study
and/or system simulation testing that
addresses various categories of
conditions to be simulated, as set forth
in the Reliability Standard, to verify
system performance under contingency
conditions involving the failure of a
single element with or without a fault.
The Reliability Standard requires that
planned outages of transmission
equipment be considered for those
demand levels for which planned
outages are performed. When system
simulations indicate that the system
cannot meet the performance
requirements stipulated in the standard,
a documented plan to achieve system
performance requirements must be
prepared. The specific study elements
selected from each of the categories for
assessments are subject to approval by
the associated regional reliability
organization.
ii. Staff Preliminary Assessment
1070. Staff stated that its general
concerns regarding stressing the system
during simulations and event-based
contingencies apply to TPL–002–0. In
other words, TPL–002–0 does not
require sensitivity studies to define
critical conditions and does not address
the unanticipated failure of some single
elements in the Bulk-Power System that
result in subsequent loss of multiple
elements. Staff also stated that footnotes
associated with Table 1, which are
meant to aid the interpretation of the
326 The performance requirements are set forth in
Category B of Table I of the Reliability Standard.

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performance requirements, are
ambiguous and need to be clarified so
that they are applied appropriately and
consistently by all the entities to whom
they apply. In particular staff noted that
for TPL–002–0 footnote (b) to the
Reliability Standard is sufficiently
ambiguous to allow differing
interpretations.327
1071. Staff further noted that while
the Reliability Standard defines various
categories of conditions to be simulated,
the specific study elements selected
from each of the categories for
assessments are subject to approval by
the associated regional reliability
organization, even though they may
impact neighboring utilities and
reliability coordinators.
iii. Comments
1072. NERC states that the reliability
Standards do not consider load
shedding acceptable for single
contingency events. As such, footnote
(b) provides a limited exception to the
general rule against serving load from a
radial transmission line.
1073. In addition to its comments
regarding stressing the system discussed
above, NERC comments that it intends
to pursue the following improvements:
(1) Expand the list of Category B
contingencies, and differentiate between
an element (i.e., circuit) and a system of
elements (i.e., multi-circuit line or DC
bi-pole); (2) review Category B and C
contingencies based not only on
probability, but also on reliability risk
and consider including risk
quantification methodology in the
Reliability Standards; and (3) clarify
footnote (b) of Table 1 to address staff’s
concern.
1074. CenterPoint disagrees with staff
that planners should specifically plan
for planned outages plus unplanned
outages. According to CenterPoint, it
suffices that operators currently
schedule planned outages at times when
reliability risk is minimized. Further, it
contends that planning for one planned
outage in addition to outages prescribed
in the TPL Reliability Standards would
make an N–1 requirement effectively an
N–2 requirement. Based on that
premise, it argues that no utility has
software to exhaustively test every
327 Footnote (b) reads states ‘‘Planned or
controlled interruption of electric supply to radial
customers or some local Network customers,
connected to or supplied by the Faulted element or
by the affected area, may occur in certain areas
without impacting the overall reliability of the
interconnected transmission systems. To prepare
for the next contingency, system adjustments are
permitted, including curtailments of contracted
Firm (non-recallable reserved) electric power
transfers.’’

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conceivable combination of outages or
that it would be worthwhile to do so.
1075. ReliabilityFirst and TAPS also
agree that footnote (b) needs
clarification. However, ReliabilityFirst
comments that the wording simply
reflects how the system is actually built
rather than indicating a lower level of
performance.
1076. The ISO/RTO Council
comments that the process for
determining load levels for purposes of
Requirement 1 of TPL–002–0 needs to
be standardized, and local area
networks and system adjustments
should be specifically defined.
1077. MRO finds an inconsistency in
Table 1. Under the ‘‘Loss of Demand or
Curtailed Firm Transfers’’ column for
category B the entries are all ‘‘No.’’
However, footnote (b) indicates that
curtailments of contracted firm transfers
are permitted. MRO states that the ‘‘no’’
response in this column may need to be
revised to ‘‘Planned/Controlled’’ as it is
used for other categories of
disturbances.
iv. Commission Proposal
1078. The Commission proposes to
approve TPL–002–0 as a mandatory and
enforceable Reliability Standard. In
addition, we propose to direct that
NERC develop modifications to the
Reliability Standard, as discussed
below.
1079. The Commission notes that, like
TPL–001–0, TPL–002–0 requires an
entity assessing system performance to
cover ‘‘critical system conditions and
study years’’ as deemed appropriate by
the entity performing the study, but
does not specify the rationale for
determining critical system conditions
and study years. The Commission
therefore proposes to direct NERC to
modify TPL–002–0 to require that
critical system conditions be
determined in the same manner as we
propose with regard to TPL–001–0. The
Commission also proposes that the
results of these studies be documented
to support the selection of critical
system conditions and study years used
in assessing system performance. We
also note that load models used in
system studies have a significant impact
on system performance, particularly as
they relate to the dynamic performance
of the system. The Commission
proposes that the documentation of
system studies include a description of
the load models used including
supporting rationale for their use. The
Commission expects the ERO to provide
consistency and quality control in these
interpretations and that over time one or
more performance metrics would be

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developed to assess the rigor of these
evaluations.
1080. The Commission commends
NERC’s initiative on improving the TPL
standards and proposes that NERC
modify the Reliability Standard to
expand category B to achieve
consistency in continent-wide
Reliability Standards.
1081. With regard to CenterPoint’s
concerns, we disagree that planned
outages would be considered the same
as an unexpected contingency that
would effectively turn an N–1 scenario
into an N–2 scenario. Further, the
studies/assessments should recognize
that planned outages are not scheduled
for peak periods and when required the
system is adjusted to accommodate the
planned outage. However, we do not
believe that fact justifies ignoring
planned outages altogether, as suggested
by CenterPoint. While TPL–002–0
requires consideration of planned
outages at those demand levels for
which planned outages are performed, it
does not address situations in which
critical equipment, such as a
transformer or phase angle regulator,
may be unavailable for a prolonged
period. Including such a requirement
would ensure the coordination of
contingency plans, including the
entity’s spare equipment strategy, to
return facilities to service in a timely
manner as required for reliability.
Therefore, the Commission proposes
that the ERO modify the Reliability
Standard by developing a new
requirement that would include the
reliability impact of an entity’s existing
spare equipment strategy, address the
unavailability of long lead time critical
facilities. Critical facilities are those
facilities that impact IROLs and
deliverability of generation to firm load.
1082. Order No. 661 requires all wind
generators to remain online during
voltage disturbances for specified time
periods and associated voltage levels.
Category B and some Category C events
capture these disturbances for planning
study purposes.328 We understand that
the TPL Reliability Standards implicitly
require all generators to ride through
these same types of voltage disturbances
and remain in service after the fault is
cleared. The Commission proposes to
direct NERC to modify TPL–002–0 to
explicitly state this requirement.
1083. Several commenters agree with
staff that a number of footnotes of Table
1 could be enhanced. We agree with TIS
with respect to footnote (a), which is
328 Interconnection for Wind Energy, Order No.
661, 70 FR 34993 (June 16, 2005), FERC Stats. &
Regs. ¶ 31,186 (2005), order on reh’g, Order No.
661–A, 70 FR 75,005 (Dec. 19, 2005), FERC Stats.
& Regs. ¶ 31,198 (2005).

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applicable to TPL–002–0. This states, in
part, ‘‘[a]pplicable ratings may include
Emergency Ratings applicable for short
durations as required to permit
operating steps necessary to maintain
system control.’’ 329 TIS states that on
the basis of its review of criteria,
methods and practices used for system
design, planning and analysis across the
NERC reliability regions, the footnote is
intended to provide flexibility to the
responsible planning entity to decide
the appropriate planning response. That
response could be to plan for a facility
addition or enhancement, or to develop
and document an operating guide or
procedure that can be reliably
implemented to achieve the required
system performance for the event in
question. In the latter case, the operating
action must be completed in sufficient
time to return the system to a secure
operating state with no additional loss
of firm load. The Commission proposes
to require that the phrase ‘‘permit
operating steps necessary to maintain
system control’’ be clarified to state that
the operating steps required to relieve
emergency loadings and return the
system to a normal state do not include
firm load shedding. The Commission
also proposes that these required
operating steps be identified and be
capable of returning the system to the
normal secure state within the 30
minute allowable period.
1084. Footnote (b) to Table 1 raises
three issues that need to be addressed.
Two relate to the use of planned or
controlled load interruptions under
certain circumstances, and the third
relates to the use of system adjustments
including curtailment of firm transfers
to prepare for the next contingency.
NERC and TAPS agree with the Staff
Preliminary Assessment that footnote
(b) of Table 1 could be enhanced with
regard to its intended interpretation for
contingencies associated with
transmission lines used to serve or
supply load. NERC states that it does
not consider shedding load acceptable
for single contingency events. The
Commission agrees and thus proposes to
require NERC to modify footnote (b) to
state that load shedding for a single
contingency is not permitted except in
very special circumstances where such
interruption is limited to the firm load
associated with the failure
(consequential load loss).330 For
329 NERC

TIS Report at 15.
associated with the failure could be
radial load supplied by the transmission element
that is assumed to be removed from service, load
supplied from separate transmission elements that
are both removed from service due to a single
failure, or load that is tapped onto a single
transmission element.
330 Load

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64867

purposes of clarity, the Commission
proposes to require that the phrase ‘‘to
prepare for the next contingency, system
adjustments are permitted, including
curtailments of contracted Firm (nonrecallable reserved) electric power
transfers’’ be deleted from footnote (b).
This statement is more appropriate for
Category C events and is already
captured by footnote (c) to Table 1,
which is applicable to Category C
events.
1085. While all commenters agree
with staff on the need to clarify footnote
(b), the Commission has proposed above
that footnote (b) be clarified to allow no
firm load or firm transactions to be
interrupted except consequential load
loss. NERC identifies another concern
with its example, specifically, the
acceptable magnitude and duration of
consequential load loss. The
Commission believes that the Reliability
Standard should provide some limits on
the magnitude and duration of
consequential load loss. While the
Commission does not propose to require
any specific maximum consequential
load loss level or maximum load loss
duration at this time, we do propose to
require that those values be documented
by all users of the Bulk-Power System.
1086. MRO points to the same
ambiguity in Table 1 that staff identified
in the Staff Preliminary Assessment.
The Commission interprets Table 1 to
specify no permitted loss of demand or
curtailment of firm transfers for
Category B contingencies. If the
Reliability Standard intended to use
Planned/Controlled demand loss, it
would have stated such, as they do in
other portions of the same table. It is
footnote (b) that introduces the
ambiguity, and the Commission
proposes that the footnote be viewed as
identifying rare exceptions, such as
radial customers.
1087. The Commission proposes to
require that the purpose statement of
TPL–002–0 be modified to reflect the
specific goal of the Reliability Standard.
1088. While the Commission has
identified a number of concerns with
regard to TPL–002–0, this proposed
Reliability Standard serves an important
purpose by ensuring that the future
Bulk-Power System is planned to meet
the system performance requirements of
a system, with the loss of one element.
Further, the Requirements set forth in
TPL–002–0 are sufficiently clear and
objective to provide guidance for
compliance.
1089. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission

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by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TPL–002–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TPL–002–0 that: (1) Requires that
critical system conditions be
determined in the same manner as we
propose to require for TPL–001–0; (2)
requires the inclusion of the reliability
impact of the entities’ existing spare
equipment strategy; (3) explicitly
requires all generators to ride through
the same set of Category B and C
contingencies as required for wind
generators in Order No. 661; (4) requires
documentation of load models used in
system studies and supporting rationale
for their use; (5) clarifies the phrase
‘‘permit operating steps necessary to
maintain system control;’’ and (6)
clarifies footnote (b), as discussed
above.

sroberts on PROD1PC70 with PROPOSALS

e. System Performance Following Loss
of Two or More Elements (TPL–003–0)
i. NERC Proposal
1090. NERC states that proposed
Reliability Standard TPL–003–0 ensures
that the future Bulk-Power System is
planned to meet the system performance
requirements of a system with the loss
of multiple elements. It does this by
requiring that the transmission planner
and the planning authority annually
evaluate and document the ability of its
transmission system to meet the
performance requirements of Category C
contingencies specified in Table 1 (i.e.,
events resulting in the loss of two or
more elements) for both the near-term
and the longer-term planning horizons.
TPL–003–0 requires the preparation of a
documented plan to achieve the
necessary performance requirements if
the system is unable to meet the
Category C performance criteria.
1091. TPL–003–0 applies to each
planning authority and transmission
planner. They must demonstrate
annually through valid assessments that
their portion of the interconnected
transmission system is planned to meet
the performance requirements of
Category C with all transmission
facilities in service over a planning
horizon that takes into account lead
times for corrective plans. The
Reliability Standard also requires the
applicable entities to consider planned
outages of transmission equipment for
those demand levels for which they
perform such outages. The Reliability
Standard defines various categories of

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conditions to be simulated. The specific
study elements selected from each of the
categories for assessments, including the
subset of Category C contingencies to be
evaluated, require approval by the
associated regional reliability
organization.
ii. Staff Preliminary Assessment
1092. Commission staff stated in its
Staff Preliminary Assessment that TPL–
003–0 does not require sensitivity
studies to define critical conditions and
study years, does not base its
contingencies on probable events, and
as a result has contingencies included
that would be more appropriate in
Category B contingencies treated under
TPL–002–0. Staff also stated that
footnotes associated with TPL–003–0 in
Table 1, which are meant to aid the
interpretation of the performance
requirements, are ambiguous and
require clarification to permit
appropriate and consist application.
1093. Staff noted that the purpose
statement for TPL–003–0 is identical to
those for TPL–001, TPL–003 and TPL–
004, although the Reliability Standard
has a different goal and different
requirements. Staff further noted that
while the Reliability Standard defines
various categories of conditions to be
simulated, the specific study elements
selected from each of the categories for
assessments are subject to approval by
the associated regional reliability
organization, even though they may
impact neighboring utilities and
reliability coordinators.
iii. Comments
1094. ISO/RTO Council comments
that Requirement 2 of TPL–003–0 does
not clearly define ‘‘simulation’’ and
does not define ‘‘inability to respond.’’
In addition, several commenters note
that the footnotes in Table 1 of the TPL
group of Reliability Standards could be
enhanced, including footnote (c) of
Table 1.
iv. Commission Proposal
1095. The Commission proposes to
approve proposed Reliability Standard
TPL–003–0 as a mandatory and
enforceable Reliability Standard. In
addition, we propose to direct that
NERC develop modifications to the
Reliability Standard, as discussed
below.
1096. The Commission notes that, like
TPL–001–0 and TPL–002–0, in
assessing system performance, TPL–
003–0 requires entities to cover ‘‘critical
system conditions and study years’’ as
deemed appropriate by the entity
performing the study, but does not
specify the rationale for determining

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critical system conditions and study
years. The Commission therefore
proposes that NERC modify TPL–003–0
to require that critical system conditions
be determined in the same manner
discussed above with regard to TPL–
001–0. The Commission also proposes
that the results of these studies be
documented to support the selection of
critical system conditions and study
years used in assessing system
performance. Also the Commission
notes that load models used in system
studies have a significant impact on
system performance, particularly as they
relate to the dynamic performance of the
system. The Commission proposes that
the documentation of system studies
include a description of the load models
used including supporting rationale for
their use.
1097. Several commenters agree with
Commission staff that a number of
footnotes in Table 1 to the Reliability
Standard could be enhanced. The
reference to ‘‘controlled interruption’’ of
load in regard to footnote (c), which is
applicable to TPL–003–0, suggests the
possibility of automatic load shedding
through the use of Special Protection
Systems or safety nets such as Under
Voltage Load Shedding Schemes.
Alternatively, a defined manual load
interruption could be used to deal with
short-time emergency thermal
overloads. The Commission proposes to
require that the ERO modify footnote (c)
to provide specificity regarding the use
of the term ‘‘controlled interruption’’ of
load. Further, the Commission proposes
that, in modifying TPL–003–0, the ERO
require documentation and
identification of the firm load that is
subject to the controlled interruption.
To avoid any undue negative impact on
competition, third-party impact studies
would be permitted to implement the
same or less controlled load
interruption as used by the transmission
owner.
1098. The performance requirements
for Category C events stipulate ‘‘no
cascading outages.’’ The NERC
Transmission Issues Subcommittee
identified a concern regarding the
determination of whether cascading
outages result in the evaluation of
Category C events.331 This concern
relates to the use of thermal overload or
low voltage proxies to judge the
likelihood of subsequent line or
generator trips. The Commission
proposes to require NERC to modify the
Reliability Standard to require the
applicable entities to define and
document the proxies necessary to
simulate cascading outages and to
331 See

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require that the ERO approve the
proxies.
1099. Category C3 of TPL–003–0
involves a situation in which two single
contingencies occur, with manual
system adjustments permitted after the
first contingency to prepare for the next
one. Proposed Reliability Standard IRO–
005–0 requires that the manual system
adjustments be implemented as soon as
possible and no later than 30 minutes
after the first contingency has occurred.
Should the second contingency occur
before the manual system adjustments
can be completed, the local area and
potentially the system would be
exposed to risk of cascading outages.
Recognizing this risk and its potential
consequences, some entities plan and
operate their systems so that they are
able to withstand the simultaneous
occurrence of the two contingencies for
major load pockets.332 The Commission
solicits comments on the value and
appropriateness of including such a
requirement in TPL–003–0.
1100. The Commission also notes that
TPL–003–0 would be enhanced if its
purpose statement were tailored to
reflect the specific goal of the Reliability
Standard and that each requirement
should correspond with one or more
Measures and each Measure should
correspond to a Level of NonCompliance.
1101. While the Commission has
identified a number of concerns with
regard to TPL–003–0, this proposed
Reliability Standard serves an important
purpose by ensuring that the future
Bulk-Power System is planned to meet
the system performance requirements of
a system with the loss of multiple
elements. Further, the Requirements set
forth in TPL–003–0 are sufficiently clear
and objective to provide guidance for
compliance.
1102. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TPL–003–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TPL–003–0 that: (1) Requires that
critical system conditions be
determined by conducting sensitivity
studies (as elaborated in our discussion
332 Two entities are Consolidated Edison
Company of New York and Public Service Electric
and Gas.

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of TPL–001–0); (2) clarifies footnote (c)
as discussed above; (3) requires the
applicable entities to define and
document the proxies necessary to
simulate cascading outages; and (4)
tailors the purpose statement to reflect
the specific goal of the Reliability, as
discussed above.
f. System Performance Following
Extreme Events (TPL–004–0)
i. NERC Proposal
1103. NERC states the proposed
Reliability Standard TPL–004–0 ensures
that the future Bulk-Power System is
evaluated to assess the risks and
consequences of an extreme event
involving the loss of multiple elements.
It does this by requiring that the
transmission planner and the planning
authority to evaluate and document
annually the risks and consequences of
Category D contingencies (i.e., extreme
events resulting in loss of two or more
elements or cascading) for the near-term
(five-year) planning horizon.
1104. TPL–004–0 applies to each
planning authority and transmission
planner. Each must demonstrate
annually through valid assessments that
its portion of the interconnected
transmission system is evaluated for the
risks and consequences of a number of
each of the extreme contingencies of
Category D with all transmission
facilities in service over a planning
horizon that takes into account lead
times for corrective plans. TPL–004–0
also requires that planned outages of
transmission equipment be considered
for those demand levels for which
planned outages are performed. It
defines various categories of conditions
to be simulated. The associated regional
reliability organization must approve
the specific study elements selected
from each of the categories for
assessment, including the subset of
Category D contingencies to be
evaluated.
ii. Staff Preliminary Assessment
1105. ‘‘Extreme events’’ are low
probability but high impact events. Staff
noted that while the Reliability
Standards require assessments of
extreme events, documentation of the
results and submission to the regional
reliability organization, they do not
require that consideration be given
either to reducing the probability of the
loss of multiple elements or mitigating
the impact.
1106. Staff also stated that this
proposed Reliability Standard does not
require that assessment results be
shared with impacted entities or
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staff and control room operators. Staff
noted that TPL–004–0 does not address
scenarios that are equal to or more
severe than actual weather events, such
as hurricanes that affect the Southern
United States and ice storms in the
north.
iii. Comments
1107. ISO/RTO Council believes that
Requirement R1 of TPL–004–0 needs to
be revised to provide better definition of
terms and obligations and requires
review to determine whether it is too
prescriptive in specifying responses to
extreme contingencies. ISO/RTO
Council also believes that before
Requirement R2 can be enforced,
regional seasonal assessments should be
provided to the regional reliability
organizations.
1108. MRO does not believe that it is
practical to develop deterministic
criteria for extreme events. MRO and the
New York Commission state that
Reliability Standards should not require
improvements that are not justified by
very low probability events. However, a
Reliability Standard should require
assessment and consideration of actions
necessary to resolve such events.
MidAmerican recommends that
transmission planning Reliability
Standards permit probabilistic
approaches to responding to extreme
events and events in Category D of Table
1. While the probability of extreme
events often does not warrant system
improvements, it does make sense to
require consideration of mitigating
actions or improvements whose cost is
justified by the expected benefits.
1109. ReliabilityFirst recommends
that consideration should be given to
establishing some record of studies and
identifying system weaknesses.
CenterPoint states it does not believe
that companies should be required to
share planning assessments because it
relates more to open access tariff
concerns than reliability. In addition,
sharing assessments would promote the
unnecessary disclosure of critical energy
infrastructure information.
iv. Commission Proposal
1110. The Commission proposes to
approve proposed Reliability Standard
TPL–004–0 as a mandatory and
enforceable Reliability Standard. In
addition, we propose to direct that
NERC develop modifications to the
Reliability Standard, as discussed
below.
1111. The Commission notes that, like
Reliability Standards TPL–001–0
through TPL–003–0, TPL–004–0
requires entities assessing system
performance to cover ‘‘critical system

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conditions and study years’’ the entity
performing the study deems
appropriate, but it does not specify the
rationale for determining critical system
conditions and study years. The
Commission therefore proposes that
NERC modify TPL–004–0 to require that
critical system conditions be
determined in the same manner as
discussed above with regard to TPL–
001–0. The Commission also proposes
that the results of these studies be
documented to support the selection of
critical system conditions and study
years used in assessing system
performance. Also the Commission
notes that load models used in system
studies have a significant impact on
system performance, particularly as they
relate to the dynamic performance of the
system. The Commission proposes that
the documentation of system studies
include a description of the load models
used including supporting rationale for
their use.
1112. MidAmerican and MRO agree
with Commission staff that
consideration must be given to
mitigating actions associated with
impacts of extreme events.
MidAmerican proposes using an
approach to take into account
probability, impact and value to
customers of reliability. MRO cautions
against requiring improvements that
cannot be justified. NERC also states
that Reliability Standards should not
require compliance with a high-impact,
low probability contingency imposed on
a low probability base case. The
Commission agrees that the Reliability
Standard should not require
improvements for low probability
events that cannot be justified.
However, the Commission proposes that
NERC modify TPL–004–0 to require the
identification of options for reducing
the probability or impacts of extreme
events that cause cascading outages. The
Commission also proposes that these
options be documented together with a
supporting rationale for cases where
such options were not pursued.
1113. In determining the range of
extreme events to be assessed, staff
noted that a number of recent high risk
events, such as the hurricanes affecting
the southern United States and the ice
storm in the north, resulted in a greater
impact on the Bulk-Power System in
terms of the number of elements forced
out of service than events listed in TPL–
004–0. The Commission proposes that
the contingency list of Category D be
expanded to include similar events.
1114. Staff noted that the Reliability
Standard does not explicitly require that
the results of assessments be shared
with impacted entities or communicated

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to operations planning staff and control
room operators. While CenterPoint
disfavors such information sharing, we
believe that sharing assessment results
would serve an important reliability
purpose as it would provide system
operators and impacted entities with an
opportunity to mitigate the identified
impact. However, we agree with
CenterPoint that any such requirement
should make clear that that critical
energy infrastructure information
should not be unnecessarily disclosed.
1115. The Commission also notes that
TPL–004–0 would be enhanced if its
purpose statement would be tailored to
reflect the specific goal of the standard.
In addition, the Commission proposes
that each requirement should
correspond to one or more measures and
each measure should correspond to a
level of non-compliance.
1116. While the Commission has
identified a number of concerns with
regard to TPL–004–0, this proposed
Reliability Standard serves an important
purpose by ensuring that the future
Bulk-Power System is evaluated to
assess the risks and consequences of an
extreme event involving the loss of
multiple elements. Further, the
Requirements set forth in TPL–004–0
are sufficiently clear and objective to
provide guidance for compliance.
1117. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard TPL–004–
0 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to TPL–004–0 that: (1) Requires that
critical system conditions be
determined in the same manner as
proposed for TPL–001–0; (2) requires
the identification of options for
reducing the probability or impacts of
extreme events that cause cascading; (3)
requires that, in determining the range
of extreme events to be assessed, the
contingency list of Category D be
expanded to include recent events; and
(4) tailors the purpose statement to
reflect the specific goal of the Reliability
Standard.

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g. Regional and Interregional SelfAssessment Reliability Reports (TPL–
005–0)
i. NERC Proposal
1118. NERC states that proposed
Reliability Standard TPL–005–0 ensures
that each regional reliability
organization conducts reliability
assessments of its existing and planned
regional bulk electric system annually
by requiring the regional reliability
organization to assess and document the
performance of its power system for the
current year, the next five years, and to
analyze trends for the longer-term
planning horizons.
ii. Staff Preliminary Assessment
1119. Staff noted that the Reliability
Standard identifies the regional
reliability organization as the applicable
entity.
iii. Comments
1120. NYSRC recommends that this
proposed Reliability Standard be
withdrawn, as it anticipates that
regional reliability organizations will
develop regional transmission planning
standards due to regional differences
specific to their region. CenterPoint also
suggests that the proposed Reliability
Standard be eliminated.
1121. ISO/RTO Council states that the
term and extent of assessment, as well
as the study years, are not appropriately
defined; the process for determining
load levels needs to be standardized;
and local area networks and system
adjustments need to be specifically
defined.
iv. Commission Proposal
1122. Consistent with our discussion
in the Common Issues section above, the
Commission will not propose any action
on TPL–005–0, as it applies only to
regional reliability organizations.
Accordingly, the Reliability Standard
will remain pending at the Commission.
The Commission believes that, in the
long-run, the Regional Entities should
be responsible for conducting reliability
assessments of the existing and planned
regional system. However, during the
current period of transition, the regional
reliability organizations should
continue to perform this role as they
have in the past.
1123. In addition, the Commission
agrees with the ISO/RTO Council
regarding the shortcomings in the
Reliability Standard it has identified
and proposes that NERC address these
issues in the revision to the Reliability
Standard.

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h. Assessment Data From Regional
Reliability Organizations (TPL–006–0)
i. NERC Proposal
1124. NERC states that proposed
Reliability Standard TPL–006–0 ensures
that the data necessary to conduct
reliability assessments is available by
requiring the regional reliability
organization to provide NERC with
Bulk-Power System data, reports,
demand and energy forecasts, and other
information necessary to assess
reliability and compliance with NERC
Reliability Standards and relevant
regional planning criteria.
ii. Staff Preliminary Assessment
1125. Staff noted that the Reliability
Standard identifies the regional
reliability organization as the applicable
entity.
iii. Comments
1126. NYSRC recommends that this
Reliability Standard be withdrawn
because it anticipates that regional
reliability organizations will develop
regional transmission planning
standards based on regional differences
specific to their regions. CenterPoint
also suggests eliminating this Reliability
Standard.
1127. ISO/RTO Council suggests that,
for the ERO to be successful at assessing
overall reliability, it must identify what
data and reports it needs to review in
order to ensure that adequate planning
is being conducted.
iv. Commission Proposal
1128. Consistent with our discussion
in the Common Issues section above, the
Commission will not propose any action
on TPL–006–0, as it applies only to
regional reliability organizations.
Accordingly, the Reliability Standard
will remain pending at the Commission.
The Commission believes that, in the
long-run, the Regional Entities should
be responsible for providing NERC with
Bulk-Power System data, reports,
demand and energy forecasts, and other
information necessary to assess
reliability and compliance with NERC
Reliability Standards and relevant
regional planning criteria. However,
during the current period of transition,
the regional reliability organizations
should continue to perform this role as
they have in the past.
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13. VAR: Voltage and Reactive Control
a. Overview
1129. The Version 0 Voltage and
Reactive Control (VAR) Reliability
Standard VAR–001–0 is intended to
maintain Bulk-Power System facilities
within voltage and reactive power

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limits, thereby protecting transmission,
generation, distribution, and customer
equipment and the reliable operation of
the Interconnection. The Voltage and
Reactive Control group of Reliability
Standards is intended to replace the
existing VAR–001–0 and consists of two
proposed Reliability Standards, VAR–
001–1 and VAR–002–1, with new
Requirements. These two new proposed
Reliability Standards have been
submitted by NERC as part of the
August 28, 2006 Supplemental Filing
for Commission review. Because there is
significant overlap between VAR–001–0
and version 1 Reliability Standards, the
Commission will address them
collectively below, giving due
consideration to the new Requirements
in addressing the proposed disposition
of VAR–001–1 and VAR–002–1.
b. Voltage and Reactive Control (VAR–
001–1 and VAR–002–1)
i. NERC Proposal
1130. NERC explains that VAR–001–
1 requires the transmission operator to
monitor and control voltage levels,
reactive flows, and reactive resources, in
order to keep these parameters within
their reliability limits. Further, it
requires a generator operator to provide
critical operating data to its
transmission operator, and to maintain
generator field excitation at proper
levels. The proposed Reliability
Standard would apply to transmission
operators, generator operators and
purchasing-selling entities.
1131. In its August 28, 2006
Supplemental Filing, NERC indicates
that VAR–001–1 includes three new
Requirements, designated R3, R4 and
R11, which apply to transmission
operators. Requirement R9 from VAR–
001–0, which applies to generator
operators, is now replaced with five
Requirements in VAR–002–1. Both
Reliability Standards include Measures
and Levels of Non-Compliance.
ii. Staff Preliminary Assessment
1132. The VAR Reliability Standard
requires each transmission owner to
‘‘acquire sufficient reactive resources
within its areas to protect the voltage
levels under normal and Contingency
conditions’’ and ‘‘maintain system and
Interconnection voltages within
established limits.’’ 333 The Staff
Preliminary Assessment stated that
these Requirements may not be
sufficient to assure reliable operation
when operating power systems under
conditions that make them vulnerable to
333 See

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voltage collapse.334 Staff noted that
voltage instability has been a common
causal factor in major power outages
worldwide and voltage magnitudes
alone are poor indicators of voltage
stability.
1133. The Staff Preliminary
Assessment explained that the proposed
Reliability Standard does not require
applicable entities to perform operations
planning studies that would identify the
minimum permissible pre-contingency
voltage levels and reactive power
reserves to ensure stable postcontingency voltages. In addition, the
standard does not require similar
voltage stability assessments to be
carried out periodically during real-time
operations so that system operators can
continuously respond to changing
system conditions.
1134. Because voltage and reactive
control is an integral part of
Interconnection Reliability Operating
Limits and voltage collapse can result in
widespread cascading outages, staff
expressed concern that reliable
operation of the Bulk-Power System
requires that reliability coordinators be
authorized to direct and coordinate
voltage and reactive control among
operating entities in an Interconnection,
and accordingly this standard should
also apply to reliability coordinators.
Similarly, staff noted that Requirement
R5, which requires each purchasingselling entity to arrange for reactive
resources to satisfy its reactive
requirements identified by its
transmission service provider, does not
currently apply to load-serving entities,
even though a load-serving entity is
responsible for significantly more load
than a purchasing-selling entity.
Therefore, the Reliability Standard
should also apply to load-serving
entities.
1135. Finally, staff noted that the
proposed reliability standard does not
address Recommendation No. 23 of the
Blackout Report, ‘‘[s]trengthen reactive
power and voltage control practices in
all NERC regions.’’ 335 However, staff
noted that NERC did respond to the
recommendation by establishing the
Transmission Issues Subcommittee
(TIS) which completed an evaluation of
reactive power planning and voltage
control practices.
iii. Comments
1136. NERC states that the proposed
reactive power and voltage control
334 Staff Preliminary Assessment at 118 (although
the Staff Preliminary Assessment addresses
concerns regarding the version 0 VAR Reliability
Standard, many of these same concerns apply to the
version 1 VAR Reliability Standards as well).
335 Blackout Report at 160.

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Reliability Standard is adequate and
necessary to protect the reliability of the
Bulk-Power System. It points out that,
in addition to the proposed Reliability
Standard, a number of other Version 0
standards in the IRO, TOP, and TPL
series address reactive power and
voltage control requirements and
suggests that the proposed Reliability
Standards should be viewed in their
entirety in assessing their adequacy.
1137. Nonetheless, NERC states that
staff is correct that additional
consideration regarding the
development of the Reliability Standard
related to reactive power and voltage
control, reactive reserves, and the
related subject of under-voltage load
shedding is required. It explains that, in
response to the Blackout Report
recommendations related to reactive
power and voltage control, the NERC
Planning Committee prepared a report
titled ‘‘Evaluation of Reactive Power
Planning and Voltage Control
Practices,’’ which was accepted by the
NERC board of Trustees in May 2005.
NERC states that it is committed to
developing, as a high priority, new
Reliability Standards that will
incorporate the recommendations of the
Planning Committee’s report. NERC
does not agree with the Staff
Preliminary Assessment concerning the
lack of applicability of the standard to
load-serving entities. NERC contends
that a load-serving entity that purchases
outside resources to serve its load and
uses transmission service to import that
energy acts as a purchasing-selling
entity and must arrange reactive support
services pursuant to VAR–001–0.
1138. ReliabilityFirst, on the other
hand, agrees with staff’s concern that
the proposed Reliability Standard
should apply to load-serving entities
and reliability coordinators. As a
general matter and in the specific
context of the proposed Reliability
Standard, ReliabilityFirst states the
work by NERC’s drafting team to
develop missing compliance elements
must be expedited. In addressing staff’s
primary issues with this standard,
ReliabilityFirst states that acceptable
variations in voltage used by operating
personnel should be minimized by the
development of more defined terms.
iv. Commission Proposal
1139. The Commission proposes to
approve VAR–001–1 as mandatory and
enforceable. In addition, we propose to
direct that NERC develop modifications
to the Reliability Standard, as discussed
below.
1140. As explained in the Staff
Preliminary Assessment, the proposed
Reliability Standard requires a

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transmission owner to ‘‘acquire
sufficient reactive resources within its
area to protect the voltage levels under
normal and Contingency conditions’’ 336
and ‘‘maintain system and
Interconnection voltages within
established limits.’’ 337 In the
Commission’s view, technical
requirements containing terms such as
‘‘established limits’’ or ‘‘sufficient
reactive resources’’ are not definitive
enough to address voltage instability
and to ensure reliable operations.338 As
an example of the Commission’s
concept of a more effective requirement,
NERC should consider WECC’s
Reliability Criteria, which contain
specific and definitive technical
requirements on voltage and margin
application.339 The Commission’s view
is also consistent with the NERC
Transmission Issue Subcommittee’s
findings in its ‘‘Evaluation of Reactive
Power Planning and Voltage Control
Practices.’’ 340 The Commission notes
that VAR–001–1, while adding three
new Requirements that apply to
transmission operators regarding voltage
and reactive control, still lacks the
specific and technical Requirements on
voltage and margin application to
prevent voltage instability.341 Therefore,
the Commission proposes directing
NERC to modify VAR–001–1 to include
more detailed and definitive
requirements on ‘‘established limits’’
and ‘‘sufficient reactive resources’’ to
prevent voltage instability and to ensure
reliable operations. These requirements
for ensuring voltage stability shall be
included in operations planning studies
and real-time assessment in addition to
real time operation.
1141. While real-time operations are
covered by other standards, the
requirement to perform periodic voltage
336 VAR–001–1,

Requirement R2.
Requirement R8.
338 See Staff Preliminary Assessment at 118,
citing Blackout Report at 36 (‘‘voltage magnitude
alone is a poor indicator of voltage stability’’).
339 WECC’s Reliability Criteria at 32 states ‘‘For
transfer paths, post-transient voltage stability is
required with the path modeled at a minimum of
105% of the path rating (or Operational Transfer
Capability) for system normal conditions (Category
A) and for single contingencies (Category B). For
multiple contingencies (Category C), post-transient
voltage stability is required with the path modeled
at a minimum of 102.5% of the path rating (or
Operational Transfer Capability).
340 See http://www.NERC.com/pub/sys/all_updl/
pc/tis/TIS_Reactive_Recom7a_BOTapprvd_050305.
341 VAR–001–1 Requirement R3 requires
transmission owners to specify criteria that exempt
generators from complying with Requirement R4.
Requirement R4 requires transmission owners to
specify a voltage or reactive power schedule to be
maintained by generators. Requirement R11
requires transmission operators to provide
documentation to generator owners on necessary
step-up transformer tap changes.
337 VAR–001–1,

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stability analysis in real-time operations
is not directly addressed. Because of its
importance to Bulk-Power System
reliability, as discussed in section ii
above, the Commission proposes that it
be directly addressed in VAR–001–1.
1142. Section 215(b) of the FPA
provides that users, owners and
operators of the Bulk-Power System
must comply with a Commissionapproved Reliability Standard. As
discussed above, NERC’s proposed
Reliability Standards identify the
entities to which a particular Reliability
Standard would apply according to the
NERC Functional Model. According to
NERC’s proposal, VAR–001–1 would
apply to transmission operators and
purchasing-selling entities. In
Requirement R5, purchasing-selling
entities are required to arrange for
reactive resources to satisfy their
reactive requirements as identified by
their transmission service provider.
Because purchasing-selling entities are
either self-providing or purchasing the
reactive resources, they are clearly users
of the Bulk-Power System.
1143. The Commission believes that
NERC’s proposed applicability
provision in VAR–001–1, in terms of the
Functional Model, should be expanded
to include ‘‘reliability coordinators’’ and
‘‘load-serving entities.’’ According to
NERC’s petition, ‘‘load-serving entities’’
are energy providers for end use
customers, and NERC’s functional
model defines the load serving function
as responsible for ‘‘secur[ing] energy
and transmission service (and related
Interconnected Operations Services) to
serve the end-use customer.’’ 342
Reliability coordinators and loadserving entities are operators and users
of the bulk-power system respectively,
and should be included in the
applicability of this standard as
discussed in more detail below.
1144. In a complex power grid such
as the one which exists in North
America, reliable operations can only be
ensured by coordinated efforts from all
operating entities in long term planning,
operational planning and real time
operations. To that end, the Staff
Preliminary Assessment recommended
(and ReliabilityFirst concurred) that the
applicability of this proposed Reliability
Standard extend to both reliability
coordinators and load-serving entities.
Since reliability coordinators are the
highest level of authority overseeing the
reliability of the Bulk-Power System, it
is important to include them as an
applicable entity to maintain adequate
voltage and reactive resources. As for
load-serving entities, NERC states that
342 NERC

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VAR–001–0 (and NERC’s statement
applies equally to VAR–001–1) is
indirectly applicable to a load-serving
entity in its role as a purchasing-selling
entity to the extent that it purchases
outside resources to serve its load and
uses transmission service to import that
energy. Although the Commission
agrees with this statement to the extent
that a load-serving entity is purchasing
point-to-point transmission service to
serve its load, it is not clear that a loadserving entity would become a
purchasing-selling entity when utilizing
network service to meet its load
obligations. The Commission is
interested in comments concerning
NERC’s assertion that all load serving
entities are also purchasing-selling
entities.
1145. We propose directing NERC to
add reliability coordinators and loadserving entities to the existing list of
applicable entities for VAR–001–1 for
added clarity. VAR–001–1 recognizes
that energy purchases of purchasingselling entities can increase reactive
power consumption on the Bulk-Power
System and that they must supply what
they consume. Load-serving entities also
consume reactive power. We note that
in many cases load response and loadside investment can reduce the need for
reactive power capability in the
system.343 Therefore, we propose to
include controllable load among the
reactive resources to satisfy reactive
requirements.
1146. We are also interested in
comments on the acceptable ranges of
net power factor range at the interface
that the load serving entities receive
service from the Bulk-Power System
during normal and extreme load
conditions.
1147. While the Commission has
identified a number of concerns with
regard to VAR–001–1, we believe that
the proposal serves an important
purpose in requiring users, owners and
operators of the Bulk-Power System to
maintain facilities within voltage limits.
The Commission believes it is important
for NERC to include Requirements
which contain added specificity; and
additional Requirements to perform
voltage stability assessments during
real-time operations. Nonetheless, the
proposed requirements set forth in
VAR–001–1 are sufficiently clear and
objective to provide guidance for
compliance.
1148. Accordingly, giving due weight
to the technical expertise of the ERO
and with the expectation that the
343 See Principles of Efficient and Reliable
Reactive Power Supply and Consumption: FERC
Staff Report (2005).

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Reliability Standard will accomplish the
purpose represented to the Commission
by the ERO and that it will improve the
reliability of the nation’s Bulk-Power
System, the Commission proposes to
approve Reliability Standard VAR–001–
1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5)
of the FPA and § 39.5(f) of our
regulations, the Commission proposes to
direct that NERC submit a modification
to VAR–001–1 that: (1) Includes
detailed and definitive requirements on
‘‘established limits’’ and ‘‘sufficient
reactive resources’’ as discussed above,
and identifies acceptable margins above
the voltage instability points; (2)
includes Requirements to perform
voltage stability assessments
periodically during real-time operations;
and (3) expands the applicability to
include reliability coordinators and
load-serving entities.
1149. The Commission commends
NERC and industry for their efforts in
expanding on Requirement R9, which
applied to generator operators in VAR–
001–0, and making it into several
detailed Requirements in VAR–002–1,
which apply to generator operators and
generator owners, complete with
Measures and Levels of NonCompliance to ensure appropriate
generation operation to maintain
network voltage schedules.
1150. Accordingly, the Commission
believes that Reliability Standard VAR–
002–1 is just, reasonable, not unduly
discriminatory or preferential, and in
the public interest; and proposes to
approve it as mandatory and
enforceable.
14. Glossary of Terms Used in
Reliability Standards
a. NERC Proposal
1151. In its petition, NERC submitted,
and requested approval of the Glossary
of Terms Used in Reliability Standards.
NERC states that the glossary, which
defines terms used in Reliability
Standards, initially became effective on
April 1, 2005. The glossary is updated
whenever a new or revised Reliability
Standards is approved that includes a
new term or definition. The glossary
may also be approved by a separate
action using NERC’s Reliability
Standards development process. NERC
updated the glossary in its August 28,
2006 Supplemental Filing.
b. Staff Preliminary Assessment
1152. While staff did not globally
address the NERC glossary, it did
express concern regarding the definition
of bulk electric system in the glossary.
Staff stated that differences between the

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64873

Bulk-Power System in section 215 of the
FPA and the NERC definition of bulk
electric system could create a
discrepancy that results in reliability
‘‘gaps.’’ 344 Further, in its discussion of
planning (TPL) Reliability Standards,
staff expressed concern regarding the
statutory definition of Reliable
Operation as it would impact the
contingencies to be considered in
setting system performance expectations
set forth in the TPL standard.
c. Comments
1153. Commenters note that some
glossary terms are not consistent with
the definition for those same terms in
the ERO’s Rules of Procedure. They
point to the definition of regional
reliability organization and load serving
entity as examples. Comments on the
term Bulk-Power System and Reliable
Operation are included with the TPL
chapter.
d. Commission Proposal
1154. The Commission believes that
the NERC glossary is an important
supplement to understanding the
mandatory and enforceable Reliability
Standards. While we are generally
satisfied with the NERC glossary, we
believe that it is appropriate that NERC
modify the glossary to include terms
defined in section 215(a) of the FPA.
Further, in the general Applicability
discussion we explained our specific
concerns regarding potential differences
between the statutory term Bulk-Power
System and the NERC term bulk electric
system and how to bring consistency
between the two terms. Further, in our
discussion of general issues concerning
the communication (COM) Reliability
Standards, we identified specific
concerns regarding the definitions of
transmission operator and generator
operator. We propose to direct that
NERC modify the glossary to reflect
these concerns.
1155. With regard to commenters
concerns regarding the consistency of
definitions between the glossary and the
ERO Rules of Procedure, we believe that
the ERO documents should be
consistent in their definition of a
specific term. However, we will leave it
to the ERO’s discretion whether the
glossary or the Rules of Procedure
should be modified to assure
consistency in the definition of any
particular term.
1156. Accordingly, the Commission
proposes to approve the Glossary of
Terms Used in Reliability Standards. In
addition, we propose to direct that
NERC submit, a modification to the
344 Staff

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Preliminary Assessment at 25–26.

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glossary that: (1) Includes the statutory
definitions of Bulk-Power System,
Reliable Operation, Reliability Standard,
as set forth in section 215 (a); (2)
modifies the definitions of
‘‘transmission operator’’ and ‘‘generator
operator’’ to include aspects unique to
ISO/RTO and pooled resource
organizations; (3) modifies the
definition of ‘‘bulk electric system’’
consistent with our discussion in the
Common Issues section above; and (4)
modifies the definition of terms
concerning reserves (such as operating
reserves) to include demand side
management, including controllable
load.
IV. Information Collection Statement
1157. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain reporting and
recordkeeping (collections of
information) imposed by an agency.345
The information contained here is also
subject to review under Section 3507(d)
of the Paperwork Reduction Act of
1995.346 As stated above, these 107
proposed Reliability Standards—of
which the Commission proposes to
approve 83 in a final rule—make up the
current NERC standards that the electric
industry currently is expected to
comply with on a voluntary basis.
Therefore, in proposing to adopt the
Reliability Standards, the Commission
would adopt reporting requirements

that have been implemented on a
voluntary basis for many years in most
instances. Because the reporting
requirements are usual and customary
practices in the industry, and
respondents incur the time and
financial resources in the course of their
regular activity, the transition from
voluntary to mandatory Reliability
Standards effected by this Proposed
Rule will not increase the reporting
burden nor impose any additional
information collection requirements.
1158. However, we also recognize that
there may be some smaller entities such
as municipal utilities, cooperatives and
small generators that may not have been
members of NERC and may not have
been participants in NERC’s voluntary
standards program. For such entities,
compliance with the proposed
mandatory Reliability Standards will
include compliance with reporting
requirements for the first time.
1159. It is difficult to determine
exactly how many entities fall into this
category. First, as discussed above with
regard to applicability issues, not every
proposed Reliability Standard would
apply to every user, owner or operator
of the Bulk-Power System, and each
proposed Reliability Standard contains
its own set of reporting requirements.
For example, only 24 proposed
Reliability Standards would apply to
generators, which contain 142 reporting
requirements.

1160. Further, as discussed in greater
detail below with regard to small
business flexibility, NERC has indicated
that it will propose specific limits on
the applicability of Reliability Standards
to small entities that do not have a
material impact on the Bulk-Power
System. While we do not pre-judge this
proposal, we note that Commission
acceptance of such a proposal could
also have a significant impact on the
reporting burden of small entities that
have not previously complied with the
NERC standards on a voluntary basis.
1161. In addition, some small entities
may join together in Joint Action
Agencies or other such organizations
that will be responsible for certain
aspects of their members’ compliance
with mandatory Reliability Standards.
Such umbrella organizations may lessen
the reporting burden of individual
users, owners and operators.
Accordingly, the reporting burden
estimate below, while based on the
Commission’s best information, is
subject to numerous variables. Although
there is considerable uncertainty
regarding the number of entities or the
burden on those entities for which
compliance with reliability standards
will be a new exercise and not a
customary practice, the Commission
provides below what it believes to be a
reasonable estimate based on available
information.

sroberts on PROD1PC70 with PROPOSALS

PUBLIC REPORTING BURDEN
Data collection

Number of
respondents

Number of
responses

Number of
hours per
response

Total annual
hours

FERC–725A .....................................................................................................

2,000

100

200,000

Information Collection Costs: The
Commission seeks comments on the
costs on complying with these
requirements. It has projected the
average annualized cost to be the
following:
200,000 hours @ $200 an hour = $
40,000,000.
1162. Title: Bulk Power System
Mandatory Reliability Standards.
1163. Action: Proposed Collection.
1164. OMB Control No. To be
Determined.
1165. Respondents: Businesses or
other for profit; not for profit
institutions.
1166. Frequency of Responses: On
Occasion.
1167. Necessity of the Information:
This proposed rule implements section
215(d)(2) of the FPA, which provides
345 5

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that the Commission may approve a
proposed Reliability Standard if it
determines that the proposal is just,
reasonable, not unduly discriminatory
or preferential, and in the public
interest.
1168. Internal Review: The
Commission has reviewed the proposed
reliability standards and made a
determination that these requirements
are necessary to implement section 215
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 to assure
itself, by means of internal review, that
there is specific, objective support for
346 44

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the burden estimates associated with the
information requirements.
1169. Interested person may obtain
information on the reporting
requirements by contacting the
following: Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426 [Attention:
Michael Miller, Office of the Executive
Director, Phone: (202) 502–8415, fax:
(202) 273–0873, e-mail:
[email protected].
1170. For submitting comments
concerning the collection(s) of
information and the associated burden
estimate(s), please send your comments
to the contact listed above and to the
Office of Information and Regulatory
Affairs, Office of Information and
Regulatory Affairs, Washington, DC

U.S.C. 3507(d).

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20503 [Attention: Desk Officer for the
Federal Energy Regulatory Commission,
phone (202) 395–4650, fax: (202) 395–
7285, e-mail:
[email protected].

sroberts on PROD1PC70 with PROPOSALS

V. Environmental Analysis
1171. 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.347 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.348
VI. Regulatory Flexibility Act
Certification
1172. The Regulatory Flexibility Act
of 1980 (RFA) 349 requires that a
rulemaking contain either a description
and analysis of the effect that the
proposed rule will have on small
entities or a certification that the rule
will not have a 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 and
sends the certification to the Chief
Counsel for Advocacy of the Small
Business Administration (SBA). The
SBA’s Office of Size Standards develops
the numerical definition of a small
business. (See 13 CFR 121.201.) For
electric utilities, 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 12 months did not exceed
four million megawatt hours.
1173. Section 215(b) of the FPA
requires all users, owners and operators
of the Bulk-Power System to comply
with Commission-approved Reliability
Standards. As discussed above, each
proposed Reliability Standard submitted
for approval by NERC applies to some
subset of users, owners and operators.
Each proposed Reliability Standard
includes an ‘‘applicability’’ statement
that identifies the functional classes of
entities responsible for compliance.
Such functional classes include
reliability coordinators, balancing
347 Regulations Implementing the National
Environmental Policy Act, Order No. 486, 52 FR
47,897 (Dec. 17, 1987), FERC Stats. & Regs.,
Regulations Preambles 1986–1990 ¶ 30,783 (1987).
348 18 CFR 380.4(a)(5).
349 5 U.S.C. 601–12.

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authorities, transmission operators,
transmission owners, generator
operators, generator owners, interchange
authorities, transmission service
providers, market operators, planning
authorities, transmission planners,
resource planners, load-serving entities,
purchasing-selling entities, and
distribution providers.350
1174. As explained by NERC, a
generator operator, for example, could
include any entity that operates a
generator interconnected to the grid, be
it a large unit in excess of 1,000 MW or
a small generator of one MW or less.
NERC states that to ensure that
Reliability Standards are applied cost
effectively and that the applicability of
Reliability Standards is focused on
entities having a material impact on
Bulk-Power System reliability; it will
begin providing greater specificity in the
applicability section of a Reliability
Standard.351 For example, a Reliability
Standard may identify limitations on
applicability based on electric facility
characteristics, such as generators with
a minimum nameplate rating or a
transmission facility energized at a
specified kV level or greater.352 NERC
plans to establish a set of guidelines to
address this matter.
1175. The Commission believes that
the proposed Reliability Standards may
cause some small entities to experience
significant economic impact. While the
Commission is mindful of the possible
impact on small entities, the
Commission is also concerned that
Bulk-Power System reliability not be
compromised based on an
unwillingness of entities, large or small,
to incur reasonable expenditures
necessary to preserve such reliability.
As we explained in Order No. 672:
A proposed Reliability Standard may take
into account the size of the entity that must
comply with the Reliability Standard and the
cost to those entities of implementing the
proposed Reliability Standard. However, the
ERO should not propose a ‘‘lowest common
denominator’’ Reliability Standard that
would achieve less than excellence in
operating system reliability solely to protect
against reasonable expenses for supporting
this vital national infrastructure. For
example, a small owner or operator of the
Bulk Power-System must bear the cost of
complying with each Reliability Standard
that applies to it.353

1176. While we cannot rule on the
merits until a specific proposal has been
submitted, we believe that reasonable
limits on applicability based on size
may be an acceptable alternative to
350 See

NERC Petition at 9–10.
at 81–82.
352 Id. at 10.
351 Id.

353 Order

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64875

lessen the economic impact on the
proposed rule on small entities.354 We
emphasize, however, that any such
limits must not weaken Bulk-Power
System reliability.
VII. Comment Procedures
1177. 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 January 2, 2007.
Comments must refer to Docket No.
RM06–16–000, and must include the
commenter’s name, the organization
represented, if applicable, and the
commenter’s address. Comments may be
filed either in electronic or paper
format.
1178. 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 fourteen (14)
copies of their comments to: Federal
Energy Regulatory Commission, Office
of the Secretary, 888 First Street, NE.,
Washington, DC 20426.
VIII. Document Availability
1179. 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.
1180. From the Commission’s Home
Page on the Internet, this information is
available in the Commission’s document
management system, 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.
1181. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours. For assistance,
please contact FERC Online Support at
354 See, discussion of Applicability to Small
Entities, section III.B.3. above.

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1–866–208–3676 (toll free) or 202–502–
6652 (e-mail at
[email protected]), or the
Public Reference Room at 202–502–
8371, TTY 202–502–8659 (e-mail at
[email protected]).
List of Subjects in 18 CFR Part 40
Electric power, Reporting and
recordkeeping requirements.
By direction of the Commission.
Magalie R. Salas,
Secretary.

In consideration of the foregoing, the
Commission proposes to amend Chapter
I, Title 18, Code of Federal Regulations,
by adding part 40 to read as follows:
PART 40—MANDATORY RELIABILITY
STANDARDS FOR THE BULK-POWER
SYSTEM
Sec.

40.1
40.2
40.3

Applicability.
Mandatory Reliability Standards.
Availability of Reliability Standards.

Authority: 16 U.S.C. 824o.
§ 40.1

Applicability.

(a) This part applies to all users,
owners and operators of the Bulk-Power
System within the United States (other
than Alaska or Hawaii), including, but
not limited to, entities described in
section 201(f) of the Federal Power Act.
(b) Each Reliability Standard made
effective by § 40.2 must identify the
subset of users, owners and operators of
the Bulk-Power System to which a
particular Reliability Standard applies.
§ 40.2

Mandatory Reliability Standards.

(a) Each applicable user, owner or
operator of the Bulk-Power System must
comply with Commission-approved
Reliability Standards developed by the

North American Electric Reliability
Corporation which can be obtained from
the Commission’s Public Reference
Room at 888 First Street, NE., Room 2A,
Washington, DC 20426.
(b) A proposed modification to a
Reliability Standard proposed to
become effective pursuant to § 39.5 of
this Chapter will not be effective until
approved by the Commission.
§ 40.3

Availability of Reliability Standards.

The Electric Reliability Organization
must make each effective Reliability
Standard available on its Internet Web
site.
Note: The following appendices will not be
published in the Code of Federal
Regulations.

sroberts on PROD1PC70 with PROPOSALS

APPENDIX A.—PROPOSED DISPOSITION OF STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES
Reliability standard

Title

BAL–001–0 ................
BAL–002–0 ................
BAL–003–0 ................
BAL–004–0 ................
BAL–005–0 ................
BAL–006–1 ................
CIP–001–0 .................
COM–001–0 ..............
COM–002–1 ..............
EOP–001–0 ...............
EOP–002–1 ...............
EOP–003–0 ...............
EOP–004–0 ...............
EOP–005–1 ...............
EOP–006–0 ...............
EOP–007–0 ...............

Real Power Balancing Control Performance .....................................
Disturbance Control Performance ......................................................
Frequency Response and Bias ..........................................................
Time Error Correction ........................................................................
Automatic Generation Control ............................................................
Inadvertent Interchange .....................................................................
Sabotage Reporting ...........................................................................
Telecommunications ..........................................................................
Communications and Coordination ....................................................
Emergency Operations Planning .......................................................
Capacity and Energy Emergencies ...................................................
Load Shedding Plans .........................................................................
Disturbance Reporting .......................................................................
System Restoration Plans ..................................................................
Reliability Coordination—System Restoration ...................................
Establish, Maintain, and Document a Regional Blackstart Capability
Plan.
Plans for Loss of Control Center Functionality ..................................
Documentation of Blackstart Generating Unit Test Results ..............
Facility Connection Requirements .....................................................
Coordination of Plans for New Facilities ............................................
Transmission Vegetation Management Program ..............................
Methodologies for Determining Electrical Facility Ratings ................
Electrical Facility Ratings for System Modeling .................................
Facility Ratings Methodology .............................................................
Establish and Communicate Facility Ratings ....................................
Transfer Capabilities Methodology ....................................................
Establish and Communicate Transfer Capabilities ............................
Interchange Transaction Tagging ......................................................
Interchange Transaction Tag Communication and Assessment .......
Interchange Transaction Implementation ...........................................
Interchange Transaction Modifications ..............................................
Interchange Authority Distributes Arranged Interchange ...................
Response to Interchange Authority ...................................................
Interchange Confirmation ...................................................................
Interchange Authority Distributes Status ...........................................
Implementation of Interchange ..........................................................
Interchange Coordination Exceptions ................................................
Reliability Coordination—Responsibilities and Authorities ................
Reliability Coordination—Facilities .....................................................
Reliability Coordination—Wide Area View .........................................
Reliability Coordination—Operations Planning ..................................
Reliability Coordination—Current Day Operations ............................
Reliability Coordination—Transmission Loading Relief .....................
Procedures, Processes, or Plans to Support Coordination Between
Reliability Coordinators.

EOP–008–0 ...............
EOP–009–0 ...............
FAC–001–0 ...............
FAC–002–0 ...............
FAC–003–1 ...............
FAC–004–0 ...............
FAC–005–0 ...............
FAC–008–1 ...............
FAC–009–1 ...............
FAC–012–1 ...............
FAC–013–1 ...............
INT–001–1 .................
INT–002–0 .................
INT–003–1 .................
INT–004–1 .................
INT–005–1 .................
INT–006–1 .................
INT–007–1 .................
INT–008–1 .................
INT–009–1 .................
INT–010–1 .................
IRO–001–0 ................
IRO–002–0 ................
IRO–003–1 ................
IRO–004–1 ................
IRO–005–1 ................
IRO–006–3 ................
IRO–014–1 ................

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Approve.
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Pending.

direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct

modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.

Approve; direct
Approve.
Approve.
Approve; direct
Approve; direct
Withdrawn.
Withdrawn.
Approve; direct
Approve.
Pending.
Approve; direct
Approve; direct
Withdrawn.
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve.
Approve.
Approve.
Approve.
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve.

modification.

E:\FR\FM\03NOP2.SGM

modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.

modification.
modification.
modification.
modification.
modification.
modification.

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64877

APPENDIX A.—PROPOSED DISPOSITION OF STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES—Continued
Reliability standard

Title

IRO–015–1 ................

Notifications and Information Exchange Between Reliability Coordinators.
Coordination of Real-time Activities Between Reliability Coordinators.
Documentation of TTC and ATC Calculation Methodologies ............
Review of TTC and ATC Calculations and Results ..........................
Procedure for Input on TTC and ATC Methodologies and Values ...
Documentation of Regional CBM Methodologies ..............................
Procedure for Verifying CBM Values .................................................
Procedures for Use of CBM Values ..................................................
Documentation of the Use of CBM ....................................................
Documentation and Content of Each Regional TRM Methodology ..
Procedure for Verifying TRM Values .................................................
Steady-State Data for Transmission System Modeling and Simulation.
Regional Steady-State Data Requirements and Reporting Procedures.
Dynamics Data for Transmission System Modeling and Simulation
RRO Dynamics Data Requirements and Reporting Procedures ......
Development of Interconnection-Specific Steady State System
Models.
Development of Interconnection-Specific Dynamics System Models
Actual and Forecast Demands, Net Energy for Load, Controllable
DSM.
Aggregated Actual and Forecast Demands and Net Energy for
Load.
Reports of Actual and Forecast Demand Data .................................
Forecasts of Interruptible Demands and DCLM Data .......................
Providing Interruptible Demands and DCLM Data ............................
Accounting Methodology for Effects of Controllable DSM in Forecasts.
Verification of Generator Gross and Net Real Power Capability ......
Verification of Generator Gross and Net Reactive Power Capability
Operating Personnel Responsibility and Authority ............................
Operating Personnel Training ............................................................
Operating Personnel Credentials .......................................................
Reliability Coordination—Staffing .......................................................
System Protection Coordination ........................................................
Define and Document Disturbance Monitoring Equipment Requirements.
Regional Requirements for Analysis of Misoperations of Transmission and Generation Protection Systems.
Analysis and Mitigation of Transmission and Generation Protection
System Misoperations.
Transmission and Generation Protection System Maintenance and
Testing.
Development and Documentation of Regional UFLS Programs .......
Assuring Consistency with Regional UFLS Program ........................
Underfrequency Load Shedding Equipment Maintenance Programs
UFLS Performance Following an Underfrequency Event ..................
Assessment of the Design and Effectiveness of UVLS Program .....
UVLS System Maintenance and Testing ...........................................
Special Protection System Review Procedure ..................................
Special Protection System Database ................................................
Special Protection System Assessment ............................................
Special Protection System Data and Documentation ........................
Special Protection System Misoperations .........................................
Special Protection System Maintenance and Testing .......................
Disturbance Monitoring Equipment Installation and Data Reporting
Under-Voltage Load Shedding Program Database ...........................
Under-Voltage Load Shedding Program Data ...................................
Under-Voltage Load Shedding Program Performance ......................
Reliability Responsibilities and Authorities ........................................
Normal Operations Planning ..............................................................
Planned Outage Coordination ............................................................
Transmission Operations ...................................................................
Operational Reliability Information .....................................................
Monitoring System Conditions ...........................................................
Reporting SOL and IROL Violations ..................................................
Response to Transmission Limit Violations .......................................
System Performance Under Normal Conditions ................................
System Performance Following Loss of a Single BES Element .......

IRO–016–1 ................
MOD–001–0
MOD–002–0
MOD–003–0
MOD–004–0
MOD–005–0
MOD–006–0
MOD–007–0
MOD–008–0
MOD–009–0
MOD–010–0

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

MOD–011–0 ..............
MOD–012–0 ..............
MOD–013–1 ..............
MOD–014–0 ..............
MOD–015–0 ..............
MOD–016–1 ..............
MOD–017–0 ..............
MOD–018–0
MOD–019–0
MOD–020–0
MOD–021–0

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

MOD–024–1 ..............
MOD–025–1 ..............
PER–001–0 ...............
PER–002–1 ...............
PER–003–0 ...............
PER–004–0 ...............
PRC–001–0 ...............
PRC–002–0 ...............
PRC–003–1 ...............
PRC–004–1 ...............

sroberts on PROD1PC70 with PROPOSALS

PRC–005–1 ...............
PRC–006–0 ...............
PRC–007–0 ...............
PRC–008–0 ...............
PRC–009–0 ...............
PRC–010–0 ...............
PRC–011–0 ...............
PRC–012–0 ...............
PRC–013–0 ...............
PRC–014–0 ...............
PRC–015–0 ...............
PRC–016–0 ...............
PRC–017–0 ...............
PRC–018–1 ...............
PRC–020–1 ...............
PRC–021–1 ...............
PRC–022–1 ...............
TOP–001–0 ...............
TOP–002–1 ...............
TOP–003–0 ...............
TOP–004–0 ...............
TOP–005–1 ...............
TOP–006–0 ...............
TOP–007–0 ...............
TOP–008–0 ...............
TPL–001–0 ................
TPL–002–0 ................

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Approve.
Approve.
Pending.
Pending.
Pending.
Pending.
Pending.
Approve; direct modification.
Approve; direct modification.
Pending.
Pending.
Approve; direct modification.
Pending.
Approve; direct modification.
Pending.
Pending.
Pending.
Approve; direct modification.
Approve; direct modification.
Approve.
Approve; direct modification.
Approve; direct modification.
Approve; direct modification.
Pending.
Pending.
Approve.
Approve;
Approve;
Approve;
Approve;
Pending.

direct
direct
direct
direct

modification.
modification.
modification.
modification.

Pending.
Approve.
Approve; direct modification.
Pending.
Approve.
Approve;
Approve.
Approve;
Approve;
Pending.
Pending.
Pending.
Approve.
Approve;
Approve;
Approve.
Pending.
Approve.
Approve.
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve.
Approve;
Approve;
Approve;

direct modification.
direct modification.
direct modification.

direct modification.
direct modification.

direct
direct
direct
direct
direct
direct

modification.
modification.
modification.
modification.
modification.
modification.

direct modification.
direct modification.
direct modification.

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64878

Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules

APPENDIX A.—PROPOSED DISPOSITION OF STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES—Continued
Reliability standard

Title

TPL–003–0 ................

System Performance Following Loss of Two or More BES Elements.
System Performance Following Extreme BES Events ......................
Regional and Interregional Self-Assessment Reliability Reports ......
Assessment Data from Regional Reliability Organizations ...............
Voltage and Reactive Control ............................................................
Generator Operations for Maintaining Network Voltage Schedules ..
Glossary of Terms Used in Reliability Standards ..............................
BAL–001: ERCOT: CPS2 ..................................................................
INT–001/4: WECC Tagging Dynamic Schedules and Inadvertent
Payback.
BAL–006: MISO RTO inadvertent Interchange Accounting ..............
BAL–006: MISO/SPP Financial Inadvertent Settlement ....................
INT–003: MISO/SPP Scheduling Agent ............................................
INT–003: MISO Enhanced Scheduling Agent ...................................
INT–001/3: MISO Energy Flow Information .......................................
IRO–006: PJM/MISO/SPP Enhanced Congestion Management ......

TPL–004–0 ................
TPL–005–0 ................
TPL–006–0 ................
VAR–001–1 ...............
VAR–002–1 ...............
Glossary ....................
Regional Difference ...
Regional Difference ...
Regional
Regional
Regional
Regional
Regional
Regional

Difference
Difference
Difference
Difference
Difference
Difference

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

Proposed disposition
Approve; direct modification.
Approve; direct modification.
Pending.
Pending.
Approve; direct modification.
Approve
Approve; direct modification.
Approve.
Pending.
Approve.
Approve.
Approve.
Approve.
Approve.
Pending.

APPENDIX B.—COMMENTERS ON STAFF PRELIMINARY ASSESSMENT
Abbreviation

Commenter

Alberta ................................................................................

Alberta Department of Energy; Alberta Utilities and Energy Board; Alberta Electric
System Operator.
Alcoa, Inc. and Alcoa Power Generating Company.
Allegheny Power and Allegheny Energy Supply Company, LLC.
Ameren.
American Transmission Company, LLC.
Professor Anjan Bose.
American Public Power Association.
Baltimore Gas & Electric Company.
Bonneville Power Administration.
Public Utilities Commission of the State of California.
Canadian Electricity Association.
CenterPoint Energy Houston Electric, LLC.
City of Redding, California.
Duke Energy Corporation.
E.ON U.S. LLC.
Edison Electric Institute.
FPL Energy.
Florida Reliability Coordinating Council.
Georgia System Operations Corporation.
Hydro One Networks Inc.
The ISO/RTO Council.
KeySpan—Ravenswood, LLC.
Large Public Power Council.
MEAG Power.
MidAmerican Energy Company.
Midwest Independent Transmission System Operator, Inc.
Midwest Reliability Organization.
Multiple Intervenors, an unincorporated association of approximately 55 large industrial, commercial and institutional end-use energy consumers with facilities in New
York.
National Grid USA.
Northern California Power Agency.
National Electrical Manufacturers Association.
North American Electric Reliability Council.
New York State Public Service Commission.
Northeast Power Coordinating Council.
National Rural Electric Cooperative Association.
New York State Reliability Council LLC.
Ohio Consumers’ Council.
Old Dominion Electric Cooperative.
Ontario Independent Electricity System Operator.
Pacific Gas & Electric Company.
Public Service Electric & Gas Company, PSEG Energy Resources & Trade LLC,
PSEG Power LLC.
ReliabilityFirst Corporation.
San Diego Gas & Electric Company.
Southern California Edison Company.
Southern Company Services, Inc.

sroberts on PROD1PC70 with PROPOSALS

Alcoa ..................................................................................
Allegheny ............................................................................
Ameren Services Co ..........................................................
American Transmission ......................................................
Professor Bose ...................................................................
APPA ..................................................................................
BG&E .................................................................................
BPA ....................................................................................
CPUC .................................................................................
CEA ....................................................................................
Centerpoint .........................................................................
Redding ..............................................................................
Duke ...................................................................................
E.ON U.S ...........................................................................
EEI ......................................................................................
FPL Energy ........................................................................
FRCC .................................................................................
Georgia System .................................................................
Hydro One ..........................................................................
ISO/RTO Council ...............................................................
KeySpan .............................................................................
LPPC ..................................................................................
MEAG .................................................................................
MidAmerican ......................................................................
MISO ..................................................................................
MRO ...................................................................................
Multiple Intervenors ............................................................
National Grid ......................................................................
NCPA .................................................................................
NEMA .................................................................................
NERC .................................................................................
New York Commission .......................................................
NPCC .................................................................................
NRECA ...............................................................................
NYSRC ...............................................................................
Ohio Consumers’ Council ..................................................
Old Dominion .....................................................................
Ontario IESO ......................................................................
PG&E .................................................................................
PSEG Companies ..............................................................
ReliabilityFirst .....................................................................
SDG&E ...............................................................................
SoCal Edison .....................................................................
Southern .............................................................................

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64879

APPENDIX B.—COMMENTERS ON STAFF PRELIMINARY ASSESSMENT—Continued
Abbreviation

Commenter

Southwest TDU ..................................................................
TANC ..................................................................................
TAPS ..................................................................................
TVA ....................................................................................
USDA Forest Service .........................................................
Valley Group ......................................................................
WECC ................................................................................
WECC OIWG .....................................................................

Southwest Transmission Dependent Utility Group.
Transmission Agency of Northern California.
Transmission Access Policy Study Group.
Tennessee Valley Authority.
U.S. Department of Agriculture Forest Service.
The Valley Group, Inc.
Western Electricity Coordinating Council.
Operating Issues Work Group, a work group of WECC’s Compliance Monitoring and
Operating Practices Subcommittee.
Operations and Training Subcommittee, a subcommittee of WECC’s Operating Committee.
Wisconsin Electric Power Company.

WECC/OTS ........................................................................
Wisconsin Electric ..............................................................

APPENDIX C.—ABBREVIATIONS IN THIS DOCUMENT
ACE ....................................................................................
AGC ....................................................................................
ANSI ...................................................................................
ATC ....................................................................................
BCP ....................................................................................
CBM ...................................................................................
CPS ....................................................................................
DC ......................................................................................
DCS ....................................................................................
ERO ....................................................................................
GWh ...................................................................................
IEEE ...................................................................................
IROL ...................................................................................
MW .....................................................................................
ROW ...................................................................................
SOL ....................................................................................
SPS ....................................................................................
TIS ......................................................................................
TLR .....................................................................................
TRM ....................................................................................
TTC ....................................................................................
UFLS ..................................................................................
UVLS ..................................................................................

Area Control Error.
Automatic Generation Control.
American National Standards Institute.
Available Transfer Capability.
Blackstart Capability Plan.
Capacity Benefit Margin.
Control Performance Standard.
Direct Current.
Disturbance Control Standard.
Electric Reliability Organization.
Gigawatt Hour.
Institute of Electrical and Electronics Engineers.
Interconnection Reliability Operating Limits.
Mega Watt.
Right of Way.
System Operating Limit.
Special Protection System.
Transmission Issues Subcommittee.
Transmission Loading Relief.
Transmission Reliability Margin.
Total Transfer Capability.
Under Frequency Load Shedding.
Under Voltage Load Shedding.

APPENDIX D.—HIGH PRIORITY LIST
Reliability standard

Title

sroberts on PROD1PC70 with PROPOSALS

COM–001–0 .......................................................................
COM–002–1 .......................................................................
EOP–002–0 ........................................................................
EOP–003–0 ........................................................................
EOP–008–0 ........................................................................
FAC–003–1 ........................................................................
FAC–008–1 ........................................................................
IRO–003–1 .........................................................................
IRO–006–3 .........................................................................
PER–002–0 ........................................................................
PER–003–0 ........................................................................
PER–004–0 ........................................................................
PRC–006–0 ........................................................................
PRC–020–1 ........................................................................
TOP–006–0 ........................................................................
VAR–001–1 ........................................................................

Telecommunications.
Communications and Coordination.
Capacity and Energy Emergency.
Load Shedding Plans.
Plans for Loss of Control Center Functionality.
Vegetation Management Program.
Facility Ratings Methodology.
Reliability Coordination—Wide Area View.
Reliability Coordination—Transmission Loading Relief.
Operating Personnel Training.
Operating Personnel Credentials.
Reliability Coordination—Staffing.
Development and Documentation of Regional UFLS Programs.
Under-Voltage Load Shedding Program Database.
Monitoring System Conditions.
Voltage and Reactive Control.

[FR Doc. 06–8927 Filed 11–2–06; 8:45 am]
BILLING CODE 6717–01–P

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File Type	application/pdf
File Title	Document
Subject	Extracted Pages
Author	U.S. Government Printing Office
File Modified	2006-11-03
File Created	2006-11-03