[Federal Register: November 3, 2006 (Volume 71, Number 213)]
[Proposed Rules]
[Page 64769-64879]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr03no06-19]
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Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 40
Mandatory Reliability Standards for the Bulk-Power System; Proposed
Rule
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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.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Notice of proposed rulemaking.
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SUMMARY: 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, 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:
Paragraph
Numbers
I. Introduction............................................ 1
II. Background............................................. 12
A. Voluntary Reliability Standards..................... 12
B. EPAct 2005 and Order No. 672........................ 15
C. The Electric Reliability Organization............... 21
D. NERC Petition for Approval of Reliability Standards. 24
E. Staff Preliminary Assessment........................ 29
III. Discussion............................................ 33
A. The Commission's Reliability Standards Proposal..... 33
1. Applicability................................... 35
2. Mandatory Reliability Standards................. 37
3. Availability of Reliability Standards........... 39
B. Applicability Issues................................ 42
1. Definition of User of the Bulk-Power System..... 42
2. Use of the NERC Functional Model................ 44
3. Applicability to Small Entities................. 49
4. Regional Reliability Organizations.............. 54
5. Bulk-Power System v. Bulk Electric System....... 60
C. Mandatory Reliability Standards..................... 72
1. Legal Standard for Approval of Reliability 72
Standards.........................................
2. Commission Options When Acting on a Reliability 76
Standard..........................................
3. Prioritizing Modifications to Reliability 83
Standards.........................................
4. Trial Period.................................... 90
5. International Coordination of Remands........... 94
D. Common Issues Pertaining to Reliability Standards... 96
1. Blackout Report Recommendations................. 97
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2. Measures and Levels of Non-Compliance........... 103
3. Ambiguities and Potential Multiple 108
Interpretations...................................
4. Technical Adequacy.............................. 113
5. Fill-in-the-Blank Standards..................... 116
E. Discussion of Each Individual Reliability Standard.. 124
1. BAL: Resource and Demand Balancing.............. 125
2. CIP: Critical Infrastructure Protection......... 217
3. COM: Communications............................. 232
4. EOP: Emergency Preparedness and Operations...... 263
5. FAC: Facilities Design, Connections, 343
Maintenance, and Transfer Capabilities............
6. INT: Interchange Scheduling and Coordination.... 427
7. IRO: Interconnection Reliability Operations and 497
Coordination......................................
8. MOD: Modeling, Data, and Analysis............... 588
9. PER: Personnel Performance, Training and 749
Qualifications....................................
10. PRC: Protection and Control.................... 802
11. TOP: Transmission Operations................... 951
12. TPL: Transmission Planning..................... 1037
13. VAR: Voltage and Reactive Control.............. 1129
14. Glossary of Terms Used in Reliability Standards 1151
IV. Information Collection Statement....................... 1157
V. Environmental Analysis.................................. 1171
VI. Regulatory Flexibility Act Certification............... 1172
VII. Comment Procedures.................................... 1177
VIII. Document Availability................................ 1179
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Appendix A: Proposed Disposition of Standards, Glossary and Regional
Differences
Appendix B: Commenters on Staff Preliminary Assessment
Appendix C: Abbreviations in this Document
Appendix D: High Priority List
I. Introduction
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 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 be
enforced by the ERO, subject to Commission oversight.
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\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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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
[[Page 64772]]
significant step toward achieving the statutory goal of mandatory and
enforceable Reliability Standards.
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\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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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.
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\5\ See NERC Petition at 69.
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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.
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\6\ 16 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\
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\7\ NERC Petition at 25.
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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 Bulk-Power 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 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\
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\8\ See 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 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).
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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 Bulk-Power
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
[[Page 64773]]
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.
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\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).
\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.
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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 non-compliance and
identified specific ambiguities within the standards that should be
corrected to make the standards effective.\14\
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\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.
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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, 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.
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\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.
\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).
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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, 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\
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\18\ Order No. 672 at P 262, 321-337.
\19\ Order No. 672 at P 329.
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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\
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\20\ Order No. 672 at P 332.
\21\ Id. at P 337.
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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 Interconnection-wide 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\
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\22\ 18 CFR 39.5(c)(1), (3).
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19. The Commission's regulations require the ERO to file with the
[[Page 64774]]
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\
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\23\ 18 CFR 39.5(a).
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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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\24\ 18 CFR 39.5(e).
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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, industry-
sponsored 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
enforcement authority to a Regional Entity.\25\
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\25\ Although the ERO Certification Order directs NERC to modify
the pro forma delegation agreement, the pro forma agreement will not
be re-filed 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.
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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.
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\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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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 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\
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\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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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 non-compliance.
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
[[Page 64775]]
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-the-blank' 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 Non-compliance 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 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 Alaska and Hawaii)
including, but not limited to, the entities described in section 201(f)
of the FPA. This statement is consistent with Sec. 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 Bulk-Power 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 Sec. 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 Commission-approved
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 modification to a Reliability
Standard
[[Page 64776]]
``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.
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\29\ See 16 U.S.C. 824o(d)(2).
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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-by-case basis.'' \30\
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\30\ Order No. 672 at P 99.
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43. We do not propose a generic definition of the term ``User of
the Bulk-Power 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 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 Bulk-
Power System'' that must comply with a specific Reliability Standard.
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\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-by-standard
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 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.
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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\
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\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.
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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.
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\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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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 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 Commission-approved 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.
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\36\ ERO Certification Order, 116 FERC ] 61,062, at P 689.
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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.
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\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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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
[[Page 64777]]
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.
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\39\ NERC Petition at 9.
\40\ Id. at 82.
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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.
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\41\ See, e.g., Alcoa, APPA, BPA and TAPS.
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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 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.
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\42\ For example, a dedicated phone line that would remain
operative during a power failure may suffice for a small cooperative
with minimal Bulk-Power System facilities, while a large investor-
owned utility may need a sophisticated communication system with
redundancy and diverse routing requirements.
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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.
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\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 Bulk-Power 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.
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\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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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
[[Page 64778]]
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 Sec. 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.
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\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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58. Further, the Commission proposes to require that any
Reliability Standard 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 fill-in-
the-blank standards.
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\49\ MOD-001, MOD-002, MOD-003, MOD-004, MOD-005, MOD-008, and
MOD-009.
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5. Bulk-Power System v. Bulk Electric System
60. As noted above, Commission-approved 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.
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\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.
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61. Section 215(b)(1) of the FPA provides that all users, owners
and operators of the Bulk-Power System must comply with Commission-
approved 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\
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\51\ 16 U.S.C. 824o(a)(1).
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
electricity. The NERC glossary, in contrast, states that Reliability
Standards apply to the ``bulk electric system,'' which is defined in
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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\
\52\ See NERC Petition, Exhibit A, NERC glossary at 2.
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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 Bulk-Power 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.
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\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.
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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 Bulk-Power 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\
[[Page 64779]]
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.
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\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 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.
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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.
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\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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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 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.
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\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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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.
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\
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\57\ Order No. 672 at P 262, 321-37.
\58\ Id. at P 345.
\59\ Id. at P 378.
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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.''
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\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.
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74. In Order No. 672, the Commission rejected the notion that it
would
[[Page 64780]]
presume that a proposed Reliability Standard developed through an ANSI-
certified 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.
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\62\ Order No. 672 at P 338.
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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\
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\63\ ERO Certification Order, 116 FERC ] 61,062, at P 241.
\64\ Order No. 672 at P 262, 321-37.
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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
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.
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\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 compliance information.
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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\
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\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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80. This option is appropriate for a large number of proposed
Reliability Standards where the Commission has identified improvements
which are 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\
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\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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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
[[Page 64781]]
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.
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\70\ See Appendix D (High Priority List).
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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
Non-compliance; or (3) require other relatively minor clarifications or
modifications.
87. While the Commission has identified some modifications to
Reliability Standards that it believes 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 Sec. 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.
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\71\ See, e.g., Alberta, APPA, ISO/RTO Council, PSEG, WIRAB and
WECC.
---------------------------------------------------------------------------
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\
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\72\ ERO Certification Order, 116 FERC ] 61,062, at P 462.
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92. The Commission, however, is increasingly concerned that a trial
period that commences with the effective date of mandatory Reliability
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
[[Page 64782]]
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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\73\ See Order No. 672 at P 400.
\74\ ERO Certification Order, 116 FERC ] 61,062, at P 286.
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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.
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\75\ See Staff Preliminary Assessment at 17-26.
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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 Bulk-Power 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.
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\76\ Blackout Report at Chapter 10.
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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 Standards pertaining to
the Bulk-Power System.
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\77\ NERC Comments at 40.
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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 Non-Compliance
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\
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\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 non-compliance 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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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
[[Page 64783]]
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\
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\81\ See, e.g., National Grid and BPA.
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105. We agree that it is important to have Measures and Levels of
Non-Compliance 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 setting-purposes, 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 Non-Compliance.
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\82\ NERC Comments at 104. See also NERC Petition at 83.
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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 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.
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\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.
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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.
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\84\ Staff Preliminary Assessment at 18-19.
\85\ NERC Petition at 90-91; NERC Comments at 101-02.
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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.
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\86\ See, e.g., LPPC, MISO, NEMA, SDG&E and WECC.
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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 are pleased that the ERO intends to review each
Reliability Standard to identify and address ambiguous Measures and
Levels of Non-Compliance 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.
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\87\ Staff Preliminary Assessment at 19.
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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
[[Page 64784]]
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.
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\88\ See, e.g., NPCC, SDG&E and NYSRC.
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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 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 ERO-approved 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\
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\89\ See 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.
\93\ NERC Petition at 89.
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117. The Staff Preliminary Assessment recognized that the fill-in-
the-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-the-blank
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 recommends conditional approval of these 29
remaining fill-in-the-blank standards.
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\94\ This 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.
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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 fill-in-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.
---------------------------------------------------------------------------
\96\ NERC Comments at 107.
---------------------------------------------------------------------------
121. We share commenters' concerns regarding the potential for the
fill-in-the-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
[[Page 64785]]
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.
---------------------------------------------------------------------------
\97\ Order No. 672 at P 292.
\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.
---------------------------------------------------------------------------
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.
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\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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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
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.
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.
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\100\ Center[fxsp0]Point Comments at 15.
---------------------------------------------------------------------------
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 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
process-oriented 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
[[Page 64786]]
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
Non-Compliance.
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\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.''
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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
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 control areas in
its region were able to meet CPS2 standards while the aggregate
performance of the ten control areas was not in compliance.
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\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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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 continent-wide 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\
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\104\ Order No. 672 at P 290.
\105\ Id. at P 291.
\106\ Id.
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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\
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\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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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-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.
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\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.
---------------------------------------------------------------------------
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
[[Page 64787]]
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.
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\110\ Staff Preliminary Assessment at 30.
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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 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.
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\111\ ISO-RTO Council Comments, Attachment A at 3.
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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.
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\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.
---------------------------------------------------------------------------
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 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,
[[Page 64788]]
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.
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\114\ NERC Comments at 41.
\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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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.
(b) Determination of Amount and Makeup of Contingency Reserves
155. The Commission notes that Requirement R2 of BAL-002-0 is a
``fill-in-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 non-spinning reserves should be addressed on a
consistent basis. As identified by 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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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/demand-
response.pdf.
---------------------------------------------------------------------------
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 NERC Operating
Committee with the ERO.\118\
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\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.
---------------------------------------------------------------------------
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 Sec. 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 64789]]
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.
ii. Staff Preliminary Assessment
---------------------------------------------------------------------------
\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 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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\123\ Staff Preliminary Assessment at 28-30.
---------------------------------------------------------------------------
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 and Western Interconnections
have been declining every year for the past decade.\125\ NERC's
Frequency Response White Paper discusses these issues in detail.
---------------------------------------------------------------------------
\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.
\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.
---------------------------------------------------------------------------
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 over-biased 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 frequency bias setting is
actually over-biased. 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.
---------------------------------------------------------------------------
\126\ Staff Preliminary Assessment at 28.
---------------------------------------------------------------------------
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 over-
biased. 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 over-biasing 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
[[Page 64790]]
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\
---------------------------------------------------------------------------
\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
---------------------------------------------------------------------------
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 Sec. 39.5(f) of our regulations, the Commission
proposes to direct that NERC submit a modification to BAL-003-0 that
(1) includes Levels 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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 Sec. 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
[[Page 64791]]
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.
iii. Comments
187. ReliabilityFirst agrees with Staff that Measures and Levels of
Non-Compliance 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 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.
---------------------------------------------------------------------------
\132\ Staff Preliminary Assessment at 32.
---------------------------------------------------------------------------
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 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.
---------------------------------------------------------------------------
\133\ NERC 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
.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\134\ See PJM RTO White Paper, Frequency Excursions, by Koza,
Williams and Herbsleb.
---------------------------------------------------------------------------
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
[[Page 64792]]
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 Non-Compliance. 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 Sec. 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)
i. NERC Proposal
198. BAL-006-1\135\ 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 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 agreed-to 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 Non-Compliance which states that if a balancing
authority does not timely submit its inadvertent interchange report to
the regional reliability organization, it shall be considered non-
compliant.
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 \
---------------------------------------------------------------------------
\136\ See Staff Preliminary Assessment at 32 n.63.
---------------------------------------------------------------------------
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 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-control-area
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
[[Page 64793]]
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 multi-party 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 Non-Compliance
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 demand or interchange
obligations. The 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 Sec. 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\
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\137\ BAL-006-1, filed on August 28, 2006, would extend the
regional difference to SPP.
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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 net-interchange 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.
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 Bulk-Power 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
[[Page 64794]]
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 ANSI-accredited 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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\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.
---------------------------------------------------------------------------
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-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 break-in 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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 Non-Compliance 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
[[Page 64795]]
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 Sec. 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 Non-Compliance; (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.
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.
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.
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 Non-Compliance
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\
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\143\ Staff Preliminary Assessment at 45.
---------------------------------------------------------------------------
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 real-
[[Page 64796]]
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\
---------------------------------------------------------------------------
\144\ NERC Comments at 118.
---------------------------------------------------------------------------
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 Non-Compliance.
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 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\
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\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.
---------------------------------------------------------------------------
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 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 Sec. 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
[[Page 64797]]
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.''
---------------------------------------------------------------------------
\146\ Staff Preliminary Assessment at 44.
---------------------------------------------------------------------------
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 Non-Compliance, 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.
---------------------------------------------------------------------------
\147\ COM-002-1, Requirement R1.1.
---------------------------------------------------------------------------
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 pre-identified 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.
---------------------------------------------------------------------------
\148\ Blackout Report at 107.
\149\ Staff Preliminary Assessment at 43-44.
---------------------------------------------------------------------------
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 Non-Compliance. 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 Sec. 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
[[Page 64798]]
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.
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\150\ This Requirement could be included in this communication
Reliability Standard or in an operating Reliability Standard(s), at
NERC's option.
---------------------------------------------------------------------------
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)
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 Bulk-Power System. Staff also found
the requirement that transmission operators have emergency load
reduction plans 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 load-serving 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 30-minute 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
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
[[Page 64799]]
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.
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\151\ NERC glossary at 11.
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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 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.
---------------------------------------------------------------------------
\152\ Blackout Report at 158.
---------------------------------------------------------------------------
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 non-normal 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 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 Sec. 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 30-minute
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 an emergency resulting from insufficient
[[Page 64800]]
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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\153\ Id. at 163.
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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.
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 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 Sec. 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 load-shedding 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
[[Page 64801]]
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.
---------------------------------------------------------------------------
\154\ Id. at 147.
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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 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 load-shedding 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
load-shedding 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 load-shedding 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 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.
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\155\ Id. at 147.
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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 Non-Compliance. 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.
[[Page 64802]]
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 Sec. 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.
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 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 Bulk-Power
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 Sec. 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-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 Sec. 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 Non-Compliance.
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.
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\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-
005-1.
---------------------------------------------------------------------------
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
[[Page 64803]]
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.
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 Non-Compliance 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 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\
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\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.''
---------------------------------------------------------------------------
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 Sec. 39.5(f) of our regulations, the Commission
proposes to direct that NERC submit a modification to EOP-005-1 that
(1) includes 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 Non-Compliance. 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
[[Page 64804]]
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 Non-compliance.
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 Sec. 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 Non-Compliance.
h. Establish, Maintain, and Document a Regional Blackstart Capability
Plan (EOP-007-0)
i. NERC Proposal
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 that they can perform
their expected functions as specified in the overall coordinated
regional system restoration plans.
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. Plans for Loss of Control Center Functionality (EOP-008-0)
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 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\
---------------------------------------------------------------------------
\158\ EEI Comments at 10.
---------------------------------------------------------------------------
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
[[Page 64805]]
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 Non-Compliance, 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.
---------------------------------------------------------------------------
\159\ Facilities examples include telecommunications, backup
power supplies, computer systems, and security systems
---------------------------------------------------------------------------
336. The Commission understands that backup control facilities can
be costly but, when needed, are essential for reliability. To address
the balance 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 Bulk-Power 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 Sec. 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 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
[[Page 64806]]
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.
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 post-contingency conditions and
is therefore more rigorous than TPL-001-0.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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 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 open-ended. 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
[[Page 64807]]
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 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-002-0 as
mandatory and enforceable. In addition, pursuant to section 215(d)(5)
of the FPA and Sec. 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\
---------------------------------------------------------------------------
\162\ Standard FAC-003-1 (Requirement R1.2.2).
---------------------------------------------------------------------------
365. Compliance with this standard is measured against four Levels
of Non-Compliance. 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 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, 4-inches as the approach distance for the 115 kV
voltage class.\165\
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\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.
---------------------------------------------------------------------------
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 less-stringent 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\
---------------------------------------------------------------------------
\166\ Blackout Report at 154.
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[[Page 64808]]
iii. Comments
369. NERC contends that FAC-003-1 is an excellent standard that
sets appropriate requirements for managing vegetation in transmission
rights-of-way. 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.
---------------------------------------------------------------------------
\167\ NERC Comments at 31.
\168\ ``Clearance 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.''
---------------------------------------------------------------------------
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
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.
---------------------------------------------------------------------------
\169\ E.g., EEI, Mid-American, National Grid, NRECA, PG&E, and
Southern.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\170\ E.g., Allegheny, CenterPoint, EEI, MRO, National Grid,
NRECA, NYSPUC, SCE, and Southern.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\171\ E.g., CenterPoint, National Grid, ISO/RTO Council and
Southern.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\172\ EEI Comments at 8.
---------------------------------------------------------------------------
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.
[[Page 64809]]
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 Sec. 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:
---------------------------------------------------------------------------
\173\ FAC-003-1, Requirement R1.2.
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\
---------------------------------------------------------------------------
\174\ FAC-003-1, Requirement R1.2.2 (emphasis added).
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 ``if
standard atmospheric conditions do not exist, extra care must be
taken.'' \176\
---------------------------------------------------------------------------
\175\ NERC Comments at 32.
\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.''
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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-by-case 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 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.
---------------------------------------------------------------------------
\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 Report).
\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.
---------------------------------------------------------------------------
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
[[Page 64810]]
believe that it serves an important goal of improving the reliability
of the Bulk-Power 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 Sec. 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)
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 coordinators, transmission operators, 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\
---------------------------------------------------------------------------
\180\ Blackout Report at 162.
---------------------------------------------------------------------------
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 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, jointly-owned
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. Mid-American 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, Mid-
American does not support an overly-prescriptive standard. It suggests
that staff's concerns should be directed at
[[Page 64811]]
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.
---------------------------------------------------------------------------
\181\ National Grid Comments at 19.
---------------------------------------------------------------------------
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 ``lowest common
denominator'' result. To correct this problem, the Valley Group
encourages adoption of IEEE/CIGRE guidelines for selection of weather
parameters.\182\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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.
---------------------------------------------------------------------------
\183\ MRO Comments at 8.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\184\ See NERC Comments at 61.
---------------------------------------------------------------------------
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
[[Page 64812]]
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 Sec. 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)
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 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 inter-regional and
intra-regional transfer 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
[[Page 64813]]
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.
---------------------------------------------------------------------------
\185\ Path rating process in WECC and various regional transfer
capability methodologies in the Eastern interconnection.
---------------------------------------------------------------------------
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.
i. Establish and Communicate Transfer Capability (FAC-013-1)
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.
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
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 Sec. 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.
6. INT: Interchange Scheduling and Coordination
a. Overview
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.
---------------------------------------------------------------------------
\186\ NERC 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.''
---------------------------------------------------------------------------
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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 Bulk-Power 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
[[Page 64814]]
that the INT group of Reliability Standards should be rejected.
---------------------------------------------------------------------------
\188\ Order No. 672 at P 324.
\189\ NERC Petition at 40-41.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\190\ Order No. 672 at P 249.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\191\ Currently, 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.''
---------------------------------------------------------------------------
ii. Staff Preliminary Assessment
435. Staff noted that INT-001-0 has only one Measure and no Levels
of Non-Compliance. The Version 1 standard, INT-001-1, would delete the
one Measure and, thus, would contain no Measures or Levels of Non-
Compliance.
iii. Comments
436. ISO/RTO Council generally agrees with staff that INT-001-0
lacks sufficient compliance measures. 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 point-to-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.
---------------------------------------------------------------------------
440. With regard to Allegheny's comments, we believe that all
Reliability Standards will benefit from Measures and Levels of Non-
Compliance. 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 Non-Compliance, 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 Sec. 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
[[Page 64815]]
inadvertent payback is not allowed in the WECC.\194\
---------------------------------------------------------------------------
\194\ Waiver Request--Tagging Dynamic Schedules and Inadvertent
Payback, Approved November 21, 2002. NERC Petition, Exhibit A.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\195\ Order No. 672 at P 290.
\196\ Information on this development can be found at: http://www.wecc.
[fxsp0]biz/
index.php?[fxsp0]module=pn[fxsp0]Forum&func=view[fxsp0]topic&topic=39
4.
---------------------------------------------------------------------------
d. Regional Difference to INT-001-1 and INT-003-1: MISO Energy Flow
Information
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 ISO must provide equivalent information
to Reliability Authorities as would be extracted from a transaction
tag.''
---------------------------------------------------------------------------
\197\ Waiver Request--Energy Flow Information, Approved July 16,
2003. (Attached to NERC's proposed Reliability Standards).
---------------------------------------------------------------------------
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.'' \198\However, 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\
---------------------------------------------------------------------------
\198\ Order No. 672 at P 290.
\199\ Id. at 291.
\200\ Id.
---------------------------------------------------------------------------
447. Based on the information provided by NERC, the proposed
regional difference for the INT Reliability Standards is necessary to
accommodate MISO's Commission-approved, 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.
---------------------------------------------------------------------------
\201\ See Midwest Independent Transmission System Operator,
Inc., 102 FERC ] 61,196 at P 38 (2003).
---------------------------------------------------------------------------
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 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 Non-Compliance
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 Non-Compliance. 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 Non-
Compliance. While it is important to develop Measures and Levels of
Non-Compliance, 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 Sec. 39.5(f) of our regulations, we propose directing
NERC to submit a modified Reliability
[[Page 64816]]
Standard that includes Measures and Levels of Non-Compliance.
f. Regional Differences to INT-003-1: MISO/SPP Scheduling Agent and
MISO Enhanced Scheduling Agent
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, non-participating 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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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 transactions within and
between RTOs.\205\
---------------------------------------------------------------------------
\205\ Waiver Request--Enhanced Scheduling Agent, Approved
November 16, 2003. ERC Petition, Exhibit A.
---------------------------------------------------------------------------
ii. 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 continent-wide 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\
---------------------------------------------------------------------------
\206\ Order No. 672 at P 291.
---------------------------------------------------------------------------
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
multi-control 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.
---------------------------------------------------------------------------
\207\ See Midwest Independent Transmission System Operator,
Inc., 102 FERC ] 61,196 at P 38 (2003).
---------------------------------------------------------------------------
459. Accordingly, for the reasons set forth above, the Commission
proposes to approve these two additional regional differences.
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 Non-Compliance.
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
Filing, and no comments were submitted regarding it.
iv. Commission Proposal
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 Sec. 39.5(f) of our regulations, we propose directing
NERC to submit a modification to INT-004-1 that includes Levels of Non-
Compliance.
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
[[Page 64817]]
assessments. INT-005-1 is applicable to the ``interchange authority.''
\208\
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
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 Non-
Compliance.
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 Sec. 39.5(f) of our regulations, we propose to direct
that NERC submit a modification to INT-005-1 that includes Levels of
Non-Compliance. 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 Bulk-Power System that is required to comply with
mandatory Reliability Standards.
i. Response to Interchange Authority (INT-006-1)
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
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.
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 Sec. 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 wide-area reliability viewpoint
and, where their review indicates a potential detrimental reliability
impact, communicate to the sink balancing authorities necessary
transaction modifications prior to implementation.
[[Page 64818]]
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.
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
requests additional information because 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.
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.
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
[[Continued on page 64819]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 64819-64868]] Mandatory Reliability Standards for the Bulk-Power System
[[Continued from page 64818]]
[[Page 64819]]
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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\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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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.
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\211\ Blackout Report at 163.
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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.
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.
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\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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b. General Comments
498. CenterPoint believes that the IRO series of Reliability
Standards are largely unnecessary as they are process-oriented. 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 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 re-dispatch 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, provides an adequate
understanding of
[[Page 64820]]
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 Sec. 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)
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 Non-Compliance and resubmit it for Commission approval in
November 2006.
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 Non-Compliance.
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.
---------------------------------------------------------------------------
\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 post-
contingency analysis capabilities (thermal, stability, and voltage),
and wide-area overview displays.''
---------------------------------------------------------------------------
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 Non-Compliance 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 Non-Compliance 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)
of the FPA and Sec. 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 Non-Compliance 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 Non-Compliance 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.''
---------------------------------------------------------------------------
\214\ NERC Comments at 126.
---------------------------------------------------------------------------
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
[[Page 64821]]
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\
---------------------------------------------------------------------------
\215\ Blackout Report at 159.
\216\ Id.
\217\ IRO-003-1, Requirement R1.
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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 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 Sec. 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 Non-Compliance; 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\
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\218\ Staff Preliminary Assessment at 71.
---------------------------------------------------------------------------
iii. Comments
523. NERC asserts that Requirement R1 of IRO-004-1 does require
next-day 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.
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
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
[[Page 64822]]
with system contingencies or emergencies in real-time operations.
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\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.''
---------------------------------------------------------------------------
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 Sec. 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 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 Non-Compliance 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 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.
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\221\ See NERC Comments at 43-48.
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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 30-minute 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
[[Page 64823]]
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 high price.
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 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.
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\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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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 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 Non-
Compliance 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,
coordinated Interconnection operations,
[[Page 64824]]
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 Sec. 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)
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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
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\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.
---------------------------------------------------------------------------
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\
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\227\ Blackout Report, Recommendation No. 31 at 163.
\228\ Staff Preliminary Assessment at 69.
---------------------------------------------------------------------------
iii. Comments
552. NERC explains that the TLR procedure is a method of addressing
the 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 re-dispatch and transmission reconfiguration are more
precise for a system operator to stay within SOLs and IROLs.
---------------------------------------------------------------------------
\229\ NERC Comments at 49.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\230\ Id. at 50.
---------------------------------------------------------------------------
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,
[[Page 64825]]
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.
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
556. However, ISO/RTO Council explains the limitations of TLR in
EOP-002-0 that most ISOs and RTOs use re-dispatch 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, re-dispatch 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.
---------------------------------------------------------------------------
\233\ NERC Comments at 49.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\234\ See Blackout Report at 63.
\235\ Id. at 163.
---------------------------------------------------------------------------
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 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-to-back DC lines to
mitigate contingencies without curtailing transactions. The Commission
proposes to approve its use.
---------------------------------------------------------------------------
\236\ WSCC is an old reference to WECC.
---------------------------------------------------------------------------
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 Sec. 39.5(f) of our regulations, the Commission
proposes to direct that NERC submit a modification
[[Page 64826]]
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 Non-Compliance 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.
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 non-market 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 non-discriminatory 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.
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.
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
[[Page 64827]]
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
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\
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\237\ MOD-001-0 through MOD-009-0.
\238\ MOD-010-0 through MOD-015-0.
\239\ MOD-016-0 through MOD-021-0.
\240\ MOD-024-1 through MOD-025-1.
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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 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\
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\241\ OATT Reform NOPR, 71 FR 32636 at 32658.
\242\ Id., 71 FR at 32654 and 32667.
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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.
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\243\ AFC 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.
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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 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-in-the-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)
[[Page 64828]]
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.
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 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-the-blank'' 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\
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\246\ OATT Reform NOPR at ] 155-70.
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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.
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\247\ For 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.
---------------------------------------------------------------------------
604. Further, the different approaches in calculation of ATC/
AFC,\248\ TTC, and lack of clear requirements for calculation of
existing transmission 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.
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\248\ Available Flowgate Capability is a method widely used in
the Eastern Interconnection but there is no NERC definition for that
term.
\249\ ETC includes transmission capacity set aside for both
native load and transmission reservations.
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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
[[Page 64829]]
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.
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\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.
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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, contingency outages and topology as
those used for expansion planning and operations. Consistent with the
OATT Reform NOPR, we believe that the long-term 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.
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\252\ OATT Reform NOPR at P 166.
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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\
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\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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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.
iii. Comments
613. The Commission received no specific comments regarding MOD-
002-0.
iv. Commission Proposal
614. MOD-002-0 is a ``fill-in-the-blank'' 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
[[Page 64830]]
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-the-blank'' 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)
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.
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\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.
---------------------------------------------------------------------------
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
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
optional to the transmission provider. TAPS urges the Commission to
make the calculations related to this standard transparent, consistent,
and regionally-based.
iv. Commission Proposal
624. MOD-004-0 is a ``fill-in-the-blank'' 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 \
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\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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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
[[Page 64831]]
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 non-affiliated third
party's access to the transmission system.
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 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-the-blank'' 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 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
load-serving 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
[[Page 64832]]
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 Sec. 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)
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 load-
serving entity, to report that use to the regional reliability
organization, NERC and the transmission users. The transmission service
provider is not 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 Sec. 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 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-the-blank'' 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
[[Page 64833]]
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)
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.
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-the-blank'' 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 steady-state 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
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
[[Page 64834]]
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 Sec. 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
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.
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.
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 Sec. 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
[[Page 64835]]
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.
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\
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\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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iii. Comments
682. NERC acknowledges that planning authorities also have
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-the-blank'' 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 goo