[Federal Register: April 4, 2007 (Volume 72, Number 64)]
[Rules and Regulations]
[Page 16415-16602]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr04ap07-15]
[[Page 16415]]
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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; Final Rule
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM06-16-000; Order No. 693]
Mandatory Reliability Standards for the Bulk-Power System
Issued March 16, 2007.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
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SUMMARY: Pursuant to section 215 of the Federal Power Act (FPA), the
Commission approves 83 of 107 proposed Reliability Standards, six of
the eight proposed regional differences, and the Glossary of Terms Used
in Reliability Standards developed by 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, 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. Therefore, pursuant to section
215(d)(5), we require the ERO to submit significant improvements to 56
of the 83 Reliability Standards that are being approved as mandatory
and enforceable. The remaining 24 Reliability Standards will remain
pending at the Commission until further information is provided.
The Final Rule adds a new part to the Commission's regulations,
which states that this part applies to all users, owners and operators
of the Bulk-Power System within the United States (other than Alaska or
Hawaii) and requires that each Reliability Standard identify the subset
of users, owners and operators to which that particular Reliability
Standard applies. The new regulations also require that each
Reliability Standard that is approved by the Commission will be
maintained on the ERO's Internet Web site for public inspection.
EFFECTIVE DATE: This rule will become effective June 4, 2007.
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 Markets and
Reliability, Division of Policy Analysis and Rulemaking, Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202) 502-8923.
SUPPLEMENTARY INFORMATION: Before Commissioners: Joseph T. Kelliher,
Chairman; Suedeen G. Kelly; Marc Spitzer; Philip D. Moeller; and Jon
Wellinghoff.
Table of Contents
Paragraph
I. Introduction............................................. 1
A. Background........................................... 3
1. EPAct 2005 and Order No. 672..................... 3
2. NERC Petition for Approval of Reliability 12
Standards..........................................
3. Staff Preliminary Assessment and Commission NOPR. 15
4. Notice of Proposed Rulemaking.................... 17
II. Discussion.............................................. 21
A. Overview............................................. 21
1. The Commission's Underlying Approach to Review 21
and Disposition of the Proposed Standards..........
2. Mandates of Section 215 of the FPA............... 23
3. Balancing the Need for Practicality with the 29
Mandates of Section 215 and Order No. 672..........
B. Discussion of the Commission's New Regulations....... 34
1. Applicability.................................... 34
2. Mandatory Reliability Standards.................. 40
3. Availability of Reliability Standards............ 44
C. Applicability Issues................................. 50
1. Bulk-Power System v. Bulk Electric System........ 50
2. Applicability to Small Entities.................. 80
3. Definition of User of the Bulk-Power System...... 110
4. Use of the NERC Functional Model................. 117
5. Regional Reliability Organizations............... 146
D. Mandatory Reliability Standards...................... 161
1. Legal Standard for Approval of Reliability 161
Standards..........................................
2. Commission Options When Acting on a Reliability 169
Standard...........................................
3. Prioritizing Modifications to Reliability 193
Standards..........................................
4. Trial Period..................................... 208
5. International Coordination....................... 226
E. Common Issues Pertaining to Reliability Standards.... 234
1. Blackout Report Recommendation on Liability 234
Limitations........................................
2. Measures and Levels of Non-Compliance............ 238
3. Ambiguities and Potential Multiple 264
Interpretations....................................
4. Technical Adequacy............................... 282
5. Fill-in-the-Blank Standards...................... 287
F. Discussion of Each Individual Reliability Standard... 304
1. BAL: Resource and Demand Balancing............... 305
2. CIP: Critical Infrastructure Protection.......... 446
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3. COM: Communications.............................. 473
4. EOP: Emergency Preparedness and Operations....... 542
5. FAC: Facilities Design, Connections, Maintenance, 678
and Transfer Capabilities..........................
6. INT: Interchange Scheduling and Coordination..... 796
7. IRO: Interconnection Reliability Operations and 889
Coordination.......................................
8. MOD: Modeling, Data, and Analysis................ 1007
9. PER: Personnel Performance, Training and 1325
Qualifications.....................................
10. PRC: Protection and Control..................... 1419
11. TOP: Transmission Operations.................... 1568
12. TPL: Transmission Planning...................... 1684
13. VAR: Voltage and Reactive Control............... 1847
14. Glossary of Terms Used in Reliability Standards. 1887
III. Information Collection Statement....................... 1900
IV. Environmental Analysis.................................. 1909
V. Regulatory Flexibility Act............................... 1910
VI. Document Availability................................... 1947
VII. Effective Date and Congressional Notification.......... 1950
Appendix A: Disposition of Reliability Standards, Glossary
and Regional Differences
Appendix B: Commenters on the Notice of Proposed Rulemaking
Appendix C: Abbreviations in this Document
I. Introduction
1. Pursuant to section 215 of the Federal Power Act (FPA), the
Commission approves 83 of 107 proposed Reliability Standards, six of
the eight proposed regional differences, and the Glossary of Terms Used
in Reliability Standards (glossary) developed by 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, 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.\1\ Therefore,
pursuant to section 215(d)(5), we require the ERO to submit significant
improvements to 56 of the 83 Reliability Standards that are being
approved as mandatory and enforceable. The remaining 24 Reliability
Standards will remain pending at the Commission until further
information is provided.
2. The Final Rule adds a new part to the Commission's regulations,
which states that this part applies to all users, owners and operators
of the Bulk-Power System within the United States (other than Alaska or
Hawaii) and requires that each Reliability Standard identify the subset
of users, owners and operators to which that particular Reliability
Standard applies. The new regulations also require that each
Reliability Standard that is approved by the Commission will be
maintained on the ERO's Internet Web site for public inspection.
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\1\ U.S.-Canada Power System Outage Task Force, Final Report on
the August 14 Blackout in the United States and Canada: Causes and
Recommendations (April 2004) (Blackout Report). The Blackout Report
is available on the Internet at http://www.ferc.gov/cust-protect/moi/blackout.asp
.
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A. Background
1. EPAct 2005 and Order No. 672
3. On August 8, 2005, the Electricity Modernization Act of 2005,
which is Title XII, Subtitle A, of the Energy Policy Act of 2005 (EPAct
2005), was enacted into law.\2\ EPAct 2005 adds a new section 215 to
the FPA, which requires a Commission-certified ERO to develop mandatory
and enforceable Reliability Standards, which are subject to Commission
review and approval. Once approved, the Reliability Standards may be
enforced by the ERO, subject to Commission oversight or the Commission
can independently enforce Reliability Standards.\3\
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\2\ 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.
\3\ 16 U.S.C. 824o(e)(3).
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4. On February 3, 2006, the Commission issued Order No. 672,
implementing section 215 of the FPA.\4\ Pursuant to Order No. 672, the
Commission certified one organization, NERC, as the ERO.\5\ The ERO is
required to develop Reliability Standards, which are subject to
Commission review and approval.\6\ The Reliability Standards will apply
to users, owners and operators of the Bulk-Power System, as set forth
in each Reliability Standard.
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\4\ 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).
\5\ North American Electric Reliability Corp., 116 FERC ] 61,062
(ERO Certification Order), order on reh'g & compliance, 117 FERC ]
61,126 (ERO Rehearing Order) (2006), order on compliance, 118 FERC ]
61,030 (2007) (January 2007 Compliance Order).
\6\ 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).
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5. 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.\7\ According to this guidance, a 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
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reliability goal and must contain a technically sound means to achieve
this goal. The Reliability Standard should be clear and unambiguous
regarding what is required and who is required to comply. The possible
consequences for violating a Reliability Standard should be clear and
understandable to those who must comply. There should be clear criteria
for whether an entity is in compliance with a Reliability Standard.
While a Reliability Standard does not necessarily need to reflect the
optimal method for achieving its reliability goal, a Reliability
Standard should achieve its reliability goal effectively and
efficiently. A 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.\8\
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\7\ Order No. 672 at P 262, 321-37.
\8\ Id. at P 329.
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6. A Reliability Standard may take into account the size of the
entity that must comply and the costs of implementation. A 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 physical differences in grid characteristics and
regional Reliability Standards that result in more stringent practices.
It can 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 Reliability Standard should have no undue negative effect on
competition.\9\
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\9\ Id. at P 332.
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7. Order No. 672 directs the ERO to explain how the factors the
Commission identified are satisfied and how the ERO balances any
conflicting factors when seeking approval of a proposed Reliability
Standard.\10\
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\10\ Id. at P 337.
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8. Pursuant to section 215(d)(2) of the FPA and Sec. 39.5(c) of
the Commission's regulations, the Commission will 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 will
not defer to the ERO or to such a Regional Entity with respect to the
effect of a proposed Reliability Standard or proposed modification to a
Reliability Standard on competition.\11\
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\11\ 18 CFR 39.5(c)(1), (3).
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9. The Commission's regulations require the ERO to file with the
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.\12\
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\12\ 18 CFR 39.5(a).
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10. Where a Reliability Standard requires significant improvement,
but is otherwise enforceable, the Commission approves the Reliability
Standard. In addition, as a distinct action under the statute, the
Commission directs the ERO to modify such a Reliability Standard,
pursuant to section 215(d)(5) of the FPA, to address the identified
issues or concerns. This approach will allow the proposed Reliability
Standard to be enforceable while the ERO develops any required
modifications.
11. 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.\13\ 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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\13\ 18 CFR 39.5(e).
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2. NERC Petition for Approval of Reliability Standards
12. 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 Final
Rule.\14\ 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 stated that it simultaneously filed
the proposed Reliability Standards with governmental authorities in
Canada. The Commission addresses these proposed Reliability Standards
in this rulemaking proceeding.\15\
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\14\ The filed proposed Reliability Standards are not attached
to the Final Rule 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
.
\15\ Eight proposed Reliability Standards submitted in the
August 29, 2006 filing 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.
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13. On November 15, 2006, NERC filed 20 revised proposed
Reliability Standards and three new proposed Reliability Standards for
Commission approval. The 20 revised Reliability Standards primarily
provided additional Measures and Levels of Non-Compliance, but did not
add or revise any existing Requirements to these Reliability Standards.
NERC requested that the 20 revised proposed Reliability Standards be
included as part of the Final Rule issued by the Commission in this
docket. The proposed new Reliability Standards, FAC-010-1, FAC-011-1,
and FAC-014-1, will be addressed in a separate rulemaking proceeding in
Docket No. RM07-3-000.
14. On December 1, 2006, NERC submitted in Docket No. RM06-16-000
an informational filing entitled ``NERC's Reliability Standards
Development Plan: 2007--2009'' (Work Plan). NERC stated it was
submitting the Work Plan to inform the Commission of NERC's program to
improve the Reliability Standards that currently are the subject of the
Commission's rulemaking proceeding.
3. Staff Preliminary Assessment and Commission NOPR
15. 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 identifies staff's
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 reviews
and identifies issues regarding each individual Reliability Standard
but did not make specific recommendations regarding the appropriate
Commission action on a particular proposal.
16. Comments on the Staff Preliminary Assessment were due by June
26, 2006. Approximately 50 entities filed comments in response to
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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, the comments
and other related issues.
4. Notice of Proposed Rulemaking
17. The Commission issued the NOPR on October 20, 2006, and
required that comments be filed within 60 days after publication in the
Federal Register, or January 2, 2007.\16\ The Commission granted the
request of several commenters to extend the comment date to January 3,
2007. Several late-filed comments were filed. The Commission will
accept these late-filed comments. A list of commenters appears in
Appendix A.
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\16\ Mandatory Reliability Standards for the Bulk Power System,
Notice of Proposed Rulemaking, 71 FR 64,770 (Nov. 3, 2006), FERC
Stats. & Regs., Vol IV, Proposed Regulations, ] 32,608 (2006).
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18. On November 27, 2006, the Commission issued a notice on the 20
revised Reliability Standards filed by NERC on November 15, 2006. In
the notice, the Commission explained that, because of their close
relationship with Reliability Standards dealt with in the October 20,
2006 NOPR, the Commission would address these 20 revised Reliability
Standards in this proceeding.\17\ The notice provided an opportunity to
comment on the revised Reliability Standards, with a comment due date
of January 3, 2007.
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\17\ The modified 20 Reliability Standards are: CIP-001-1; COM-
001-1; COM-002-2; EOP-002-2; EOP-003-1; EOP-004-1; EOP-006-1; INT-
001-2; INT-003-2; IRO-001-1; IRO-002-1; IRO-003-2; IRO-005-2; PER-
004-1; PRC-001-1; TOP-001-1; TOP-002-2; TOP-004-1; TOP-006-1; and
TOP-008-1.
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19. The Commission issued a notice on NERC's Work Plan on December
8, 2006. While the Commission sought public comment on NERC's filing
because it was informative on the prioritization of modifying
Reliability Standards raised in the NOPR, the notice emphasized that
the Work Plan was filed for informational purposes and NERC stated that
it is not requesting Commission action on the Work Plan.
20. On February 6, 2007, NERC submitted a request for leave to file
supplemental information, and included a revised version of the NERC
Statement of Compliance Registry Criteria (Revision 3). NERC noted that
it had submitted with its NOPR comments an earlier version of the same
document.\18\
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\18\ See NERC comments, Attachment B.
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II. Discussion
A. Overview
1. The Commission's Underlying Approach To Review and Disposition of
the Proposed Standards
21. In this Final Rule, the Commission takes the important step of
approving the first set of mandatory and enforceable Reliability
Standards within the United States in accordance with the provisions of
new section 215 of the FPA. The Commission's action herein marks the
official departure from reliance on the electric utility industry's
voluntary compliance with Reliability Standards adopted by NERC and the
regional reliability councils and the transition to the mandatory,
enforceable Reliability Standards under the Commission's ultimate
oversight through the ERO and, eventually, the Regional Entities, as
directed by Congress. As we discuss more fully below, in deciding
whether to approve, approve and direct modifications, or remand each of
the proposed Reliability Standards in this Final Rule, our overall
approach has been one of carefully balancing the need for practicality
during the time of transition with the imperatives of section 215 of
the FPA and Order No. 672, and other considerations.
22. In addition, our action today is informed by the August 14,
2003 blackout which affected significant portions of the Midwest and
Northeast United States and Ontario, Canada and impacted an estimated
50 million people and 61,800 megawatts of electric load. As noted in
the NOPR, a joint United States-Canada task force found that the
blackout was caused by several entities violating NERC's then-effective
policies and Reliability Standards.\19\ Those violations directly
contributed to the loss of a significant amount of electric load. The
joint task force identified both the need for legislation to make
Reliability Standards mandatory and enforceable with penalties for
noncompliance, as well as particular Reliability Standards that needed
corrections to make them more effective in preventing blackouts.
Indeed, the August 2003 blackout and the recommendations of the joint
task force helped foster enactment of EPAct 2005 and new section 215 of
the FPA.
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\19\ NOPR at P 14.
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2. Mandates of Section 215 of the FPA
23. The imperatives of section 215 of the FPA address not only the
protection of the reliability of the Bulk-Power System but also the
reliability roles of the Commission, the ERO, the Regional Entities,
and the owners, users and operators of the Bulk-Power System.\20\
First, section 215 specifies that the ERO is to develop and enforce a
comprehensive set of Reliability Standards subject to Commission
review. Section 215 explains that a Reliability Standard is a
requirement approved by the Commission that is intended to provide for
the Reliable Operation of the Bulk-Power System. Such requirement may
pertain to the operation of existing Bulk-Power System facilities,
including cybersecurity protection, or it may pertain to the design of
planned additions or modifications to such facilities to the extent
necessary to provide for reliable operation of the Bulk-Power
System.\21\
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\20\ Generally speaking, the nation's Bulk-Power System has been
described as consisting of ``generating units, transmission lines
and substations, and system controls.'' 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. The
transmission 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,
transmission lines and other parts of the transmission system,
including control facilities, serve to transmit electricity in bulk
from generation sources to concentrated areas of retail customers,
while the distribution system moves the electricity to where these
retail customers consume it at a home or business.
\21\ 16 U.S.C. 824o(a)(3).
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24. Second, the reliability mandate of section 215 of the FPA
addresses not only the comprehensive maintenance of the reliable
operation of each of the elements of the Bulk-Power System, it also
contemplates the prevention of incidents, acts and events that would
interfere with the reliable operation of the Bulk-Power System.
Further, section 215 seeks to prevent an instability, an uncontrolled
separation or a cascading failure, whether resulting from either a
sudden disturbance, including a cybersecurity incident, or an
unanticipated failure of the system elements. In order to avoid these
outcomes, the various elements and components of the Bulk-Power System
are to be operated within equipment and electric system thermal,
voltage and stability limits.\22\
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\22\ ``The term `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 a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system
elements.'' 16 U.S.C. 824o(a)(4).
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25. Third, section 215 of the FPA explains that the Bulk-Power
System broadly encompasses both the facilities
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and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) as well as the
electric energy from generation facilities needed to maintain
transmission system reliability.\23\ Further, section 215 explains that
the interconnected transmission network within an Interconnection is a
geographic area in which the operation of Bulk-Power System components
is synchronized such that the failure of one such component, or more
than one such component, may adversely affect the ability of the
operators of other components within the system to maintain reliable
operation of the facilities within their control.\24\ A Cybersecurity
Incident is explained to be a malicious act that disrupts or attempts
to disrupt the operation of programmable electronic devices and
communication networks including hardware, software or data that are
essential to the reliable operation of the Bulk-Power System.\25\
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\23\ 16 U.S.C. 824o(a)(1).
\24\ 16 U.S.C. 824o(a)(5).
\25\ 16 U.S.C. 824o(a)(8).
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26. Next, as to the reliability roles of the Commission and others,
section 215 of the FPA explains that the ERO must file each of its
Reliability Standards and any modification thereto with the
Commission.\26\ The Commission will consider a number of factors before
taking any action with respect thereto. We may approve the Reliability
Standard or its modification only if we determine that it is just,
reasonable, and not unduly discriminatory or preferential and in the
public interest to do so. Also, in doing so, we are instructed to give
due weight to the technical expertise of the ERO concerning the content
of a proposed standard or a modification thereto. We must also give due
weight to an Interconnection-wide Regional Entity with respect to a
proposed Reliability Standard to be applicable within that
Interconnection, except for matters concerning the effect on
competition.\27\
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\26\ ``The Electric Reliability Organization shall file each
Reliability Standard or modification to a Reliability Standard that
it proposes to be made effective under this section with the
Commission.'' 16 U.S.C. 824o(d)(1).
\27\ ``The Commission may approve, by rule or order, a proposed
Reliability Standard or modification to a Reliability Standard if it
determines that the standard is just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The
Commission shall give due weight to the technical expertise of the
Electric Reliability Organization with respect to the content of a
proposed standard or modification to a Reliability Standard and to
the technical expertise of a regional entity organized on an
Interconnection-wide basis with respect to a Reliability Standard to
be applicable within that Interconnection, but shall not defer with
respect to the effect of a standard on competition. A proposed
standard or modification shall take effect upon approval by the
Commission.'' 16 U.S.C. 824o(d)(2).
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27. Similarly, in considering whether to forward a proposed
Reliability Standard to the Commission for approval, the ERO must
rebuttably presume that a proposal from a Regional Entity organized on
an Interconnection-wide basis for a Reliability Standard or
modification to a Reliability Standard to be applicable on an
Interconnection-wide basis is just, reasonable, and not unduly
discriminatory or preferential, and in the public interest.\28\ The
Commission may also give deference to the advice of a Regional Advisory
Body organized on an Interconnection-wide basis in regard to whether a
proposed Reliability Standard is just, reasonable and not unduly
discriminatory or preferential and in the public interest, as it may
apply within the region.\29\
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\28\ 16 U.S.C. 824o(d)(3).
\29\ 16 U.S.C. 824o(j).
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28. Finally, the Commission is further instructed to remand to the
ERO for further consideration any standard or modification that it does
not approve in whole or part.\30\ We may also direct the ERO to submit
a proposed Reliability Standard or modification that addresses a
specific problem if we consider this course of action to be
appropriate.\31\ Further, if we find that a conflict exists between a
Reliability Standard and any function, rule, order, tariff, rate
schedule, or agreement accepted, approved, or ordered by the Commission
applicable to a transmission organization,\32\ and if we determine that
the Reliability Standard needs to be changed as a result of such a
conflict, we must order the ERO to develop and file with the Commission
a modified Reliability Standard for this purpose.\33\
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\30\ 16 U.S.C. 824o(d)(4).
\31\ 16 U.S.C. 824o(d)(5).
\32\ Under section 215, a transmission organization is a RTO,
ISO, independent transmission provider or other Transmission
Organization finally approved by the Commission for the operation of
transmission facilities. 16 U.S.C. 824o(a)(6).
\33\ 16 U.S.C. 824o(d)(6).
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3. Balancing the Need for Practicality With the Mandates of Section 215
and Order No. 672
29. In enacting section 215, Congress chose to expand the
Commission's jurisdiction beyond our historical role as primarily an
economic regulator of the public utility industry under Part II of the
FPA. Many entities not previously touched by our economic regulatory
oversight are within our reliability purview and these entities will
have to familiarize themselves not only with the new reliability
obligations under section 215 of the FPA and the Reliability Standards
that we are approving in this Final Rule, but also any proposed
Reliability Standards or improvements that may implicate them that are
under development by the ERO and the Regional Entities.\34\ We have
taken these and other considerations into account and have tried to
reach an appropriate balance among them.
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\34\ Section 215(b) of the FPA provides that, for purposes of
approving Reliability Standards and enforcing compliance with such
standards, the Commission shall have jurisdiction over those
entitles that had previously been excluded under section 201(f) of
the FPA. Section 201(f) excludes the United States, a state or any
political subdivision of a state, an electric cooperative that
receives financing under the Rural Electrification Act of 1936, 7
U.S.C. 901 et seq., or that sells less than 4,000,000 megawatt hours
of electricity per year, or any agency, authority, or
instrumentality of any one or more of the foregoing, or any
corporation which is wholly owned, directly or indirectly, by any
one or more of the foregoing, or any officer, agent, or employee of
any of the foregoing acting as such in the course of his official
duty, unless such provision makes specific reference thereto. 16
U.S.C. 824(f).
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30. First, we have decided, as proposed in our NOPR, to approve
most of the Reliability Standards that the ERO submitted in this
proceeding, even though concerns with respect to many of the
Reliability Standards have been voiced. As most of these Reliability
Standards are already being adhered to on a voluntary basis, we are
concerned that to remand them and leave no standard in place in the
interim would not help to ensure reliability when such standards could
be improved over time. In these cases, however, the concerns
highlighted below merit the serious attention of the ERO and we are
directing the ERO to consider what needs to be done and how to do so,
often by way of descriptive directives.\35\
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\35\ In Order No. 672, we decided, in response to some
commenters' suggestions that a Reliability Standard should address
the ``what'' and not the ``how'' of reliability and that the actual
implementation should be left to entities such as control area
operators and system planners, that in some limited situations,
there may be good reason to do so but, for the most part, in other
situations the ``how'' may be inextricably linked to the Reliability
Standard and may need to be specified by the ERO to ensure the
enforcement of the standard. Since leaving out implementation
features could sacrifice necessary uniformity, create uncertainty
for the entity that has to follow the standard, make enforcement
difficult, or increase the complexity of the Commission's oversight
and review process, we left it to the ERO to reach the appropriate
balance between reliability principles and implementation features.
Order No. 672 at P 260. We also decided that the Commission's
authority to order the ERO to address a particular reliability topic
is not in conflict with other provisions of Order No. 672 that
assigned the responsibility for developing a proposed Reliability
Standard to the ERO. Order No. 672 at P 416.
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31. We emphasize that we are not, at this time, mandating a
particular
[[Page 16421]]
outcome by way of these directives, but we do expect the ERO to respond
with an equivalent alternative and adequate support that fully explains
how the alternative produces a result that is as effective as or more
effective that the Commission's example or directive.
32. We have sought to provide enough specificity to focus the
efforts of the ERO and others adequately. We are also sensitive to the
concern of the Canadian Federal Provincial Territorial Working Group
(FPT) about the status of an existing standard that is already being
followed on a voluntary basis. The FPT suggests, for example, that
instead of remanding an existing Reliability Standard, the Commission
should conditionally approve the standard pending its modification.\36\
We believe the action we take today is similar in many respects to this
approach.
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\36\ FPT letter to Chairman Kelliher (submitted on July 10,
2006) (placed in the record of this proceeding).
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33. We have also adopted a number of other measures to mitigate
many of the difficulties associated with the electric utility
industry's preparation for and transition to mandatory Reliability
Standards. For instance, we are directing the ERO and Regional Entities
to focus their enforcement resources during an initial period on the
most serious Reliability Standard violations. Moreover, because
commenters have raised valid concerns as discussed below, our Final
Rule relies on the existing NERC definition of bulk electric system and
its compliance registration process to provide as much certainty as
possible regarding the applicability and responsibility of specific
entities under the approved standards. This approach should also
assuage the concerns of many smaller entities.
B. Discussion of the Commission's New Regulations
1. Applicability
34. In the NOPR, the Commission proposed to add Sec. 40.1(a) to
the regulations. The Commission proposed that Sec. 40.1(a) would
provide 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 section
215(b) of the FPA and Sec. 39.2 of the Commission's regulations.
35. The Commission further proposed to add Sec. 40.1(b), which
would require each Reliability Standard made effective under this Part
to identify the subset of users, owners and operators to whom that
particular Reliability Standard applies.
a. Comments
36. NERC agrees with the Commission's proposal to add the text of
Sec. 40.1(b) to its regulations to require that each Reliability
Standard identify the subset of users, owners and operators to which
that particular Reliability Standard applies and believes this
requirement is currently established in NERC's Rules of Procedure.
37. TANC supports proposed Sec. 40.1. It states that requiring
each Reliability Standard to identify the subset of users, owners and
operators to whom it applies, thereby limiting the scope of the broad
phrase ``users, owners and operators,'' is a critical step to removing
ambiguities from the Reliability Standards. According to TANC, the
proposed text of Sec. 40.1 would eliminate ambiguities with regard to
the entity responsible for complying with each Reliability Standard. In
this way, Regional Entities and other interested parties will be
allowed to weigh in during the Reliability Standards development
process on the breadth of each standard and may urge NERC to accept any
necessary regional variations that are necessary to maintain adequate
reliability within the region.
38. APPA believes that the Commission's proposal to add Sec. 40.1
and 40.2 to its regulations is generally appropriate and acceptable,
but the regulatory language should be amended to make clear the exact
universe of users, owners and operators of the Bulk-Power System to
which the mandatory Reliability Standards apply. It recommends that the
regulations provide that determinations as to applicability of
standards to particular entities shall be resolved by reference to the
NERC compliance registry.
b. Commission Determination
39. The Commission adopts the NOPR's proposal to add Sec. 40.1 to
the Commission's regulations. The Commission disagrees with APPA's
suggestion to define here the exact universe of users, owners and
operators of the Bulk-Power System to which the mandatory Reliability
Standards apply. Rather, consistent with NERC's existing approach, we
believe that it is appropriate that each Reliability Standard clearly
identify the subset of users, owners and operators to which it applies
and the Commission determines applicability on that basis. As we
discuss later, we approve NERC's current compliance registry to provide
certainty and stability in identifying which entities must comply with
particular Reliability Standards.
2. Mandatory Reliability Standards
40. The Commission proposed to add Sec. 40.2(a) to the
Commission's regulations. The proposed regulation text would require
that each applicable user, owner and operator of the Bulk-Power System
comply with Commission-approved Reliability Standards developed by the
ERO, and would provide 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.
41. The Commission further proposed to add Sec. 40.2(b) to its
regulations, providing that a modification to a Reliability Standard
proposed to become effective pursuant to Sec. 39.5 shall not be
effective until approved by the Commission.
a. Comments
42. NERC concurs with the Commission's proposal to require NERC to
provide to the Commission a copy of all approved Reliability Standards
for posting in its Public Reference Room. NERC agrees with the
Commission that neither the text nor the title of an approved
Reliability Standard should be codified in the Commission's
regulations.
b. Commission Determination
43. For the reasons discussed in the NOPR, the Commission generally
adopts the NOPR's proposal to add Sec. 40.2 to the Commission's
regulations.\37\ However, after consideration, the Commission has
determined that it is not necessary to have the approved Reliability
Standards on file in the Commission's public reference room and on the
NERC Web site. Therefore, we will require that all Commission-approved
Reliability Standards be available on the ERO's Web site, with an
effective date, and revise Sec. 40.2(b) to remove the following
language: ``Which can be obtained from the Commission's Public
Reference Room at 888 First Street, NE., Room 2A, Washington, DC,
20426.'' Further, to be consistent with Part 39 of our regulations, we
remove the reference to NERC and replace it with ``Electric Reliability
Organization.''
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\37\ NOPR at P 37.
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3. Availability of Reliability Standards
44. The Commission proposed to add Sec. 40.3 to the regulation
text, which requires that the ERO maintain in electronic format that is
accessible from the Internet the complete set of effective
[[Page 16422]]
Reliability Standards that have been developed by the ERO and approved
by the Commission. The Commission stated that it 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 noted that NERC
currently maintains the existing, voluntary Reliability Standards on
the NERC Web site.
45. While the NOPR discusses each Reliability Standard and
identifies the Commission's proposed disposition for each Reliability
Standard, we did not propose to codify either the text or the title of
an approved Reliability Standard in the Commission's regulations.
Rather, we proposed that each user, owner or operator of the Bulk-Power
System must comply with applicable Commission-approved Reliability
Standards that are available in the Commission's Public Reference Room
and on the Internet at the ERO's Web site. We stated that this approach
is consistent with the statutory options of approving a proposed
Reliability Standard or modification to a Reliability Standard ``by
rule or order.'' \38\
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\38\ See 16 U.S.C. 824o(d)(2).
---------------------------------------------------------------------------
a. Comments
46. NERC states that it can successfully implement the Commission's
proposal to require NERC to maintain in electronic format that is
accessible from the Internet the complete set of Reliability Standards
that have been developed by the ERO and approved by the Commission.
NERC currently maintains a public Web site displaying the existing,
voluntary Reliability Standards for access by users, owners and
operators of the Bulk-Power System. Once the proposed Reliability
Standards are approved by the Commission, NERC will modify its Web site
to distinguish which Reliability Standards have been approved by the
Commission for enforcement in the United States.
47. EEI states that the approval of Reliability Standards should be
through a rulemaking rather than an order, except in very rare
circumstances, because of the open nature of the rulemaking process.
Where the Commission decides to proceed by order, EEI states that the
Commission should give notice and an opportunity to comment on any
proposed Reliability Standards.
b. Commission Determination
48. For the reasons discussed in the NOPR, the Commission adopts
the NOPR's proposal to add Sec. 40.3 to the Commission's regulations;
however the Commission has further clarified the proposed regulatory
text.\39\ We clarify that the ERO must post on its Web site the
currently effective Reliability Standards as approved and enforceable
by the Commission. Further, we require the effective date of the
Reliability Standards must be included in the posting.
---------------------------------------------------------------------------
\39\ NOPR at P 39-41.
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49. In response to EEI, the Commission anticipates that it will
address most, if not all, new Reliability Standards proposed by NERC
through a rulemaking process. However, we retain the flexibility to
address matters by order where appropriate, consistent with the statute
and our regulations.\40\ In Order No. 672, the Commission stated that
it would provide notice and opportunity for public comment except in
extraordinary circumstances and, on rehearing, clarified that any
decision by the Commission not to provide notice and comment when
reviewing a proposed Reliability Standard will be made in accordance
with the criteria established in section 553 of the Administrative
Procedure Act.\41\
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\40\ See 16 U.S.C. 824o(d)(2) (``the Commission may approve, by
rule or order, a proposed Reliability Standard or modification * *
*''); 18 CFR 39.5(c).
\41\ See Order No. 672 at P 308; Order No 672-A at P 26.
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C. Applicability Issues
1. Bulk-Power System v. Bulk Electric System
50. The NOPR observed that, for purposes of section 215, ``Bulk-
Power System'' means:
(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. The NERC glossary, in contrast, states that Reliability
Standards apply to the ``bulk electric system,'' which is defined by
its regions in terms of a voltage threshold and configuration, 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.\42\
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\42\ NERC Glossary at 2. All citations to the Glossary in this
Final Rule refer to the November 1, 2006 version filed on November
15, 2006.
52. In the NOPR, the Commission proposed 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.\43\ However, the Commission interpreted the term ``bulk
electric system'' to apply to: (1) 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 and (2) transmission to all significant local distribution
systems (but not the distribution system itself), transmission to load
centers and transmission connecting generation that supplies electric
energy to the system. The Commission proposed that, if a question arose
concerning which underlying transmission system limits or supplements
the operation of the higher voltage transmission system, the ERO would
determine the matter on a case-by-case basis.
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\43\ NOPR at P 66-70. The Commission explained in the NOPR that
regional definitions had not been submitted and it would not
determine the appropriateness of any regional definition in the
current rulemaking proceeding. Id. at n. 56.
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53. The Commission solicited comment on its 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.
54. Further, the NOPR explained that 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. Thus, the NOPR proposed that, in the long run, NERC
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 of Reliability Standards, and that NERC's revision is
consistent with the statutory term Bulk-Power System.
a. Comments
55. Most commenters, including NERC, NARUC, APPA, National Grid,
EEI and Ontario IESO, believe that the Commission should only impose
Reliability Standards on those entities that fall under NERC's
definition of bulk electric system as it existed under the voluntary
regime. They state that, by extending the definition of bulk electric
system, the Commission goes beyond
[[Page 16423]]
what is necessary to protect Bulk-Power System reliability, creates
uncertainty and will divert resources from monitoring compliance of
those entities that could have a material impact on Bulk-Power System
reliability.
56. Entergy, however, agrees with the Commission that NERC's
definition of bulk electric system is not adequate and agrees with the
Commission's proposed interpretation. ISO-NE does not oppose the NOPR's
approach on how to interpret the term ``Bulk-Power System,'' but it
states that this broader scope justifies a delay in the date civil
penalties take effect, to January 1, 2008, to provide the industry
sufficient time to review the Commission's Final Rule and to adjust to
the expanded reach of the Reliability Standards.
57. NERC, APPA and NRECA maintain that there was no intentional
distinction made by Congress between ``Bulk-Power System'' (as defined
in section 215) and the ``bulk electric system'' (as defined by the
NERC glossary). NERC asserts that recent discussions with stakeholders
confirm NERC's belief that there was no distinction intended. Moreover,
NERC is not aware of any documentation that suggests a distinction was
intended. NRECA argues that legislative intent and prior usage do not
support the Commission's approach to defining the Bulk-Power System.
NRECA concedes that no conference committee report accompanied EPAct
2005, but it notes that the Congressional Research Service specifies in
its manual on statutory interpretation that ``[W]here Congress borrows
terms of art in which are accumulated the legal tradition and meaning
of centuries of practice, it presumably knows and adopts the cluster of
ideas that were attached to each borrowed word in the body of learning
from which it was taken.'' \44\
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\44\ NRECA, citing Morissette v. United States, 342 U.S. 246,
263 (1952).
---------------------------------------------------------------------------
58. TAPS states that the Commission cannot lawfully ``interpret''
the bulk electric system definition contrary to its terms. According to
TAPS, the Commission cannot include facilities below 100 kV ``that
could limit or supplement the operation of the higher voltage
transmission systems,'' in the bulk electric system, even if they are
``necessary for operating'' the bulk system, because these facilities
are not included in NERC's definition of bulk electric system.
59. NERC states that the Commission's proposal that NERC's ``bulk
electric system'' should apply to all of the equal to or greater than
100 kV transmission systems and any underlying transmission system
(less than 100 kV) that could limit or supplement the operation of the
higher voltage transmission systems is a significant expansion over
what the industry has historically regarded as the bulk electric
system, both in terms of the facilities covered and the entities
involved. While NERC agrees with the Commission that Congress intended
to give the Commission broad jurisdiction over the reliability of the
Bulk-Power System, it does not believe this is the right time for the
Commission to define the full extent of its jurisdiction or that the
approach proposed in the NOPR is the right way to do so. In addition,
NERC does not believe it is legally necessary for the Commission to
extend its jurisdiction to the limits in a single step.
60. NERC states that the Commission should make clear in this Final
Rule that its jurisdiction is at least as broad as the historic NERC
definition of ``bulk electric system'' and that the Commission will use
that definition for the near term. NERC asserts that the Commission
should also make clear that it is not deciding in this docket the full
scope of its jurisdiction and is reserving its right to consider a
broader definition. Instead, NERC states that the Commission should
focus on approving an initial set of Reliability Standards for the core
set of users, owners and operators that have the most significant
impact on the reliability of the Bulk-Power System. NERC maintains that
this core set has been defined through its use of the terms ``bulk
electric system'' and ``responsible entities'' provided in the NERC
Glossary, the ``Applicability'' section of each Reliability Standard
and substantive requirements of the standards themselves, and NERC's
registration of specific entities that are responsible for compliance
with the Reliability Standards.
61. NRECA argues that the definition of ``Bulk-Power System''
contained in section 215(a)(1) reflects Congressional intent to codify
the established materiality component because Congress limited the
definition of Bulk-Power System to facilities and control systems
necessary for operating an interconnected electric energy transmission
network and electric energy from generation facilities needed to
maintain transmission system reliability. NRECA argues that these
limiting terms mean that not all transmission facilities are included.
In NRECA's view, the definition of the Bulk-Power System within the
meaning of section 215 cannot extend to radial facilities to
``significant local distribution systems,'' ``load centers,'' or local
transmission facilities unless otherwise ``necessary for'' (i.e.,
material to) the reliable operation of the interconnected grid.
Further, NRECA states that the definition of ``Reliable Operation'' in
section 215(a) focuses on the reliable operation of the Bulk-Power
System and not the protection of local load per se.
62. Certain commenters assert that expanding the scope of the
Commission's jurisdiction and the scope of the Reliability Standards in
this proceeding would be an unanticipated expansion of the reach of the
existing Reliability Standards implemented with insufficient due
process and may cause jurisdictional concerns.\45\ They state that the
Reliability Standards under consideration were developed and approved
through NERC's Reliability Standards development process with the
intention that they would apply based on the industry's historical
conception of the bulk electric system and that the outcome might have
been different using the Commission's proposed definition. NERC
therefore argues that it would be inappropriate to assume that the
requirements of the existing Reliability Standards would be relevant to
an expanded set of entities or an expanded scope of facilities under a
broader definition of the Bulk-Power System. NERC also asserts that
there is no reasonable justification for subjecting ``thousands of
small entities'' to the costs of compliance with the Reliability
Standards when there is no reasonable justification to do so in terms
of incremental benefit to the reliability of the Bulk-Power System.
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\45\ See, e.g., NERC, TAPS and NRECA.
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63. NRECA, APPA and others argue that the Commission's
interpretation would undermine, rather than promote, reliability.
According to these commenters, the Commission's interpretation would
require new definitions, such as one for ``load center,'' and otherwise
creates confusion. For example, Small Entities Forum states that it is
concerned with the inclusion of ``transmission connecting generation
that supplies electric energy to the system'' because that could
include any transmission connected to any generation of any size.
64. APPA objects to the Commission's statement that ``[t]he
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.'' APPA states that it does
not believe there is an industry ``understanding'' that the bulk
electric system or the Bulk-Power System
[[Page 16424]]
necessarily encompass all transmission facilities that connect major
generation stations to distribution systems or that there is a bright
line between transmission and distribution facilities. APPA interprets
these terms as describing the backbone facilities that integrate
regional transmission networks.
65. NERC's approach to moving forward with the enforcement of
mandatory Reliability Standards is to register the specific entities
that NERC will hold accountable for compliance with the Reliability
Standards. The registration will identify all entities that are
material to the reliability of the Bulk-Power System. NERC maintains
its most important role is to mitigate noncompliant behavior regardless
of an entity's registration. Further, NERC asserts that all that it and
the Commission give up by using the registration approach is, at most,
``one penalty, one time'' for an entity. That is, if there is an entity
that is not registered and NERC later discovers that the entity can
have a material impact on the reliability of the Bulk-Power System,
NERC has the ability to add the entity, and possibly other entities of
a similar class, to the registration list and to direct corrective
action by that entity on a going forward basis.\46\ Thereafter, of
course, the entity would be subject to sanctions. APPA, TANC, AMP-Ohio
and NPCC support this approach. While SoCal Edison believes that there
can be no single definition of Bulk-Power System, it states that NERC's
registry is a good starting point to developing general criteria for
what facilities should be subject to the Reliability Standards.
---------------------------------------------------------------------------
\46\ See Rules of Procedure, Sec. 500.
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66. AMP-Ohio supports NERC's proposal to include any additional
entities or facilities that it believes could have a detrimental effect
on the reliability of the bulk electric system on a case-by-case basis
over time. Further, Ontario IESO suggests that if the Commission
believes that NERC's definition of bulk electric system excludes
facilities that should be subject to Reliability Standards for reasons
other than preventing cascading outages, the Commission could submit a
detailed request through the ERO Reliability Standards development
process.
67. NERC and EEI believe that, in the long run, NERC should be
directed to develop, through its Reliability Standards development
process, a single process to identify the specific elements of the
Bulk-Power System that must comply with Reliability Standards under
section 215. According to NERC, the Commission, the states, and all
other stakeholders would benefit tremendously from a deliberate
dialogue on these matters. NERC asks that the Commission not directly
define the outer limits of its jurisdiction under section 215, but
requests that the Commission direct NERC to undertake certain
activities to reconcile the definitions of bulk electric system and
Bulk-Power System and report the results back to the Commission.
68. Similarly, TAPS, APPA, Duke and MidAmerican state that, if
there is a problem with NERC's current definition of the bulk electric
system, the Commission should require NERC to revisit it using the ANSI
process to give ``due weight'' to NERC's technical expertise. AMP-Ohio,
TANC, Georgia Operators and Entergy state that Regional Entities should
play a primary role in defining the facilities that are subject to a
Reliability Standard because the Regional Entities will have more
detailed system knowledge in their regions than NERC or the Commission.
69. The Connecticut Attorney General, the Connecticut DPUC and the
New England Conference of Public Utilities Commissioners maintain that
NERC's definition of the ``bulk electric system'' exceeds the
Commission's jurisdiction by including generation that is not needed to
maintain transmission system reliability and therefore intrudes into
state jurisdiction over generation resource adequacy matters and is
unlawful. According to Connecticut DPUC, section 215(a)(1) of the FPA
excludes from federal regulation (1) facilities that are used in local
distribution, (2) facilities and control systems that are not necessary
for operating an interconnected electric energy transmission network or
part of a network and (3) electric energy from generating facilities
not needed to maintain transmission system reliability. Connecticut
DPUC maintains that, in contrast, NERC's definition replaces the FPA
definition with criteria based on voltage thresholds for transmission
facilities and electric energy from generating facilities. According to
Connecticut DPUC, NERC's definition does not comply with section
215(a)(1) because it includes facilities and equipment that are neither
``necessary'' for operation of the transmission network nor ``needed''
to maintain transmission system reliability. The Connecticut Attorney
General and Connecticut DPUC, therefore, urge the Commission to reject
this definition.
70. Further, in Connecticut DPUC's view, because the Commission
cannot adopt NERC's definition of bulk electric system, it cannot
expand the boundaries of its jurisdiction farther than the bulk
electric system. It maintains that Congress did not give the Commission
jurisdiction to mandate and enforce all Reliability Standards,
especially those related to the long-term adequacy of generation
resources; therefore, the Commission may not delegate to an ERO
authority that it does not have. APPA also states that the Commission
expanded the definition of the bulk electric system so that it may
affect facilities subject to state reliability jurisdiction, such as
low-voltage transmission systems that affect only the local areas
served by those facilities, which do not cause cascading outages,
without explaining why it is necessary to federalize reliability
responsibility for outages on these facilities.
71. NARUC and New York Commission maintain that the Commission's
proposed interpretation of what facilities constitute the Bulk-Power
System is inconsistent with section 215 of the FPA. They state that the
ability of a facility to ``limit or supplement'' the transmission
system does not automatically mean that a facility is necessary for
operating an interconnected transmission system, as required by the
FPA, or for maintaining system reliability. According to NARUC,
Congress only authorized the Commission to approve Reliability
Standards necessary for operating an interconnected electric energy
transmission network. Although the NOPR interpretation includes these
underlying facilities, it also covers others that are not required to
operate an interconnected transmission network.
72. Moreover, NARUC and New York Commission state that the NOPR
proposal to define Bulk-Power System as all facilities operating at or
above 100 kV exceeds the Commission's jurisdiction. According to NARUC
and New York Commission, there is generally a layer of ``area''
transmission facilities below the ``Bulk-Power System'' and above
distribution facilities that move energy within a service territory and
toward load centers. However, NARUC and New York Commission claim that
only a small subset of these underlying facilities assists in
maintaining the reliability of the Bulk-Power System.
73. Several commenters, including New York Commission, NYSRC,
Massachusetts DTE, NPCC, TANC and Ontario IESO, support a functional,
impact-based approach to applying Reliability Standards. According to
NPCC, neither NERC nor section 215 of the FPA provide a rigorous
approach to
[[Page 16425]]
determining which elements play a role in maintaining reliability of
the bulk electric system. These commenters generally state that an
impact-based approach would define those elements necessary for
Reliable Operation and ensure that compliance and enforcement efforts
concentrate on those facilities that materially affect the Reliable
Operation of the interconnected Bulk-Power System, while at the same
time balancing the costs imposed by mandatory Reliability Standards
with the reliability improvement realized on the interconnected Bulk-
Power System.
74. Ontario IESO maintains that reliability impact is a process of
assessing facilities to determine if, due to recognized contingencies
and other test criteria, they represent a significant adverse impact
beyond a local area. This assessment will be the basis of a consistent
test methodology the ERO must develop to define the facilities included
within the overall Bulk-Power System to which a Reliability Standard
would apply. Ontario IESO states that the Commission should direct the
ERO to take the lead in developing the impact assessment procedure to
provide a consistent and uniform methodology that can be applied by any
Regional Entity. Ontario IESO does not support the Commission's
proposal to limit case-by-case determinations to underlying
transmission systems operating at less than 100 kV.
b. Commission Determination
75. The Commission agrees with commenters that, at least initially,
expanding the scope of facilities subject to the Reliability Standards
could create uncertainty and might divert resources as the ERO and
Regional Entities implement the newly created enforcement and
compliance regime. Further, we agree with commenters that unilaterally
modifying the definition of the term bulk electric system is not an
effective means to achieve our goal. For these reasons, the Commission
is not adopting the proposed interpretation contained in the NOPR.
Rather, for at least an initial period, the Commission will rely on the
NERC definition of bulk electric system \47\ and NERC's registration
process to provide as much certainty as possible regarding the
applicability to and the responsibility of specific entities to comply
with the Reliability Standards in the start-up phase of a mandatory
Reliability Standard regime.\48\
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\47\ ``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.''
\48\ See Section II.C.2., Applicability to Small Entities,
infra.
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76. However, we disagree with NERC, APPA and NRECA that there is no
intentional distinction between Bulk-Power System and bulk electric
system. NRECA states that ``[W]here Congress borrows terms of art in
which are accumulated the legal tradition and meaning of centuries of
practice, it presumably knows and adopts the cluster of ideas that were
attached to each borrowed word in the body of learning from which it
was taken.'' \49\ In this instance, however, Congress did not borrow
the term of art--bulk electric system--but instead chose to create a
new term, Bulk-Power System, with a definition that is distinct from
the term of art used by industry. In particular, the statutory term
does not establish a voltage threshold limit of applicability or
configuration as does the NERC definition of bulk electric system.
Instead, section 215 of the FPA broadly defines the Bulk-Power System
as ``facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion
thereof) [and] electric energy from generating facilities needed to
maintain transmission system reliability.'' Therefore, the Commission
confirms its statements in the NOPR that the Bulk-Power System reaches
farther than those facilities that are included in NERC's definition of
the bulk electric system.\50\
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\49\ Citing Morissette v. United States, 342 U.S. 246, 263
(1952).
\50\ NOPR at P 66. For these same reasons, the Commission
rejects the position of those commenters that suggest the statutory
definition of Bulk-Power System is more limited than the NERC
definition of bulk electric system.
---------------------------------------------------------------------------
77. Although we are accepting the NERC definition of bulk electric
system and NERC's registration process for now, the Commission remains
concerned about the need to address the potential for gaps in coverage
of facilities. For example, some current regional definitions of bulk
electric system exclude facilities below 230 kV and transmission lines
that serve major load centers such as Washington, DC and New York
City.\51\ The Commission intends to address this matter in a future
proceeding. As a first step in enabling the Commission to understand
the reach of the Reliability Standards, we direct the ERO, within 90
days of this Final Rule, to provide the Commission with an
informational filing that includes a complete set of regional
definitions of bulk electric system and any regional documents that
identify critical facilities to which the Reliability Standards apply
(i.e., facilities below a 100 kV threshold that have been identified by
the regions as critical to system reliability).
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\51\ See id. at P 64-65 & n.53-54.
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78. The Commission believes that the above approach satisfies
concerns raised by NARUC and New York Commission that the proposal to
interpret Bulk-Power System exceeds the Commission's jurisdiction. When
the Commission addresses this matter in a future proceeding, it will
consider NARUC's and New York Commission's comments regarding the
``layer of `area' transmission.''
79. We disagree with commenters claiming that the ERO's definition
of bulk electric system is broader than the statutory definition of
Bulk-Power System. Connecticut Attorney General, Connecticut DPUC and
others argue that the ERO's definition of bulk electric system exceeds
the Commission's jurisdiction by including generation that is not
needed to maintain transmission system reliability and, therefore,
intrudes into state jurisdiction over generation resource adequacy.
First, none of the Reliability Standards submitted by the ERO set
requirements for resource adequacy. Moreover, commenters have not
adequately supported their claim that the ``threshold'' in the NERC
definition of bulk electric system that includes facilities ``generally
operated at 100 kV or higher'' is broader than the statutory phrase
``electric energy from generation facilities needed to maintain
transmission system reliability.'' As stated explicitly in the NERC
definition, this is a ``general'' threshold and allows leeway to
address specific circumstances. On its face, the NERC definition is not
overbroad; as applied, it must be interpreted and applied consistent
with the statutory language in section 215. Finally, as stated above,
we believe that the ERO definition of bulk electric system is narrower
than the statutory definition of Bulk-Power System.
2. Applicability to Small Entities
80. The NOPR discussed NERC's plan to, in the future, identify in a
particular Reliability Standard limitations on applicability based on
electric facility characteristics.\52\ The Commission agreed 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,
[[Page 16426]]
the Commission stated that a ``blanket waiver'' approach that would
exempt entities below a threshold level from compliance with all
Reliability Standards would not be appropriate because there may be
instances where a small entity's compliance is critical to reliability.
The Commission also proposed to direct NERC to develop procedures that
permit a joint action agency or similar organization to accept
compliance responsibility on behalf of their members.
---------------------------------------------------------------------------
\52\ Id. P 49-53.
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81. In addition, the Commission solicited 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 and, if so, what, if any, process the ERO or Regional
Entity should provide when making such a determination.
a. Identifying Applicable Small Entities
i. Comments
82. While certain commenters, including EEI, FirstEnergy, SERC,
Xcel and Entergy, agree with the Commission that a blanket waiver to
exempt small entities from compliance is not appropriate because there
may be instances where a small entity's compliance is critical to
reliability, APPA, ELCON, Process Electricity Committee, MEAG and South
Carolina E&G advocate a blanket waiver.
83. APPA notes that none of the entities that contributed to the
August 14, 2003 blackout were ``small entities'' within the meaning of
the Regulatory Flexibility Act. APPA and MEAG believe that the
Commission's refusal to provide for a blanket waiver to small entities
is counterproductive to maintaining reliability, as it will distract
compliance staff at NERC and the Regional Entities from identifying and
monitoring those with a material impact on reliability, and gives
insufficient deference to NERC as the ERO. APPA recommends that the
methods and procedures used to identify critical facilities that impact
the bulk electric system, regardless of size, should be the subject of
a specific set of NERC Reliability Standards. Objective, transparent
study criteria and assumptions and due process for affected entities
are essential to implement such standards properly. Regional Entities
should take advantage of industry expertise in developing and applying
the methodology for determining critical facilities.
84. According to MEAG, because the Commission has already
determined that it is not bound by the NERC compliance registry,\53\
the NOPR's approach leaves small systems, which do not appear on the
compliance registry, confused about whether the Reliability Standards
apply to them. MEAG asks the Commission to either: (1) Grant a
temporary, size-based exemption to those small entities that NERC omits
from its preliminary compliance registry; or (2) direct NERC to develop
and file with the Commission an appropriate size-based exemption for
small entities.
---------------------------------------------------------------------------
\53\ See ERO Rehearing Order at P 108.
---------------------------------------------------------------------------
85. Several commenters suggest thresholds for applying Reliability
Standards. MEAG states that an appropriate threshold level for an
exemption, on either an interim or more permanent basis, should at
least provide that a LSE or distribution provider should generally be
omitted from the compliance registry if it meets the following
criteria: (1) Its peak load is less than 25 MW and it is not directly
connected to the Bulk-Power System; (2) it is not designated as the
responsible entity for facilities that are part of a required
underfrequency load shedding (UFLS) program designed, installed, and
operated for the protection of the Bulk-Power System; or (3) it is not
designated as the responsible entity for facilities that are part of a
required undervoltage load shedding (UVLS) program designed, installed,
and operated for the protection of the Bulk-Power System. STI Capital
states that there should be a rebuttable presumption that any
generation facility below 50 MW does not pose a threat to reliability.
Moreover, more data intensive standards are beyond the ability of small
generators.
86. SERC states that exemptions should be granted through the
Reliability Standards development process. The ERO and the Regional
Entities can provide guidance in that process, and stakeholders have an
opportunity to comment on that guidance.
87. A number of commenters, including APPA, NRECA, TANC and TAPS,
ask the Commission to adopt NERC's registry guidelines and make clear
that issues of applicability will be determined with reference to the
NERC compliance registry.\54\ TAPS asks the Commission to either
approve NERC's registry criteria, or send them back to NERC for further
consideration, with mandatory application of Reliability Standards
deferred until NERC submits waiver criteria the Commission finds
acceptable. According to TAPS, these criteria do not constitute a
blanket waiver because they allow NERC and its Regional Entities to go
below the general threshold requirements where they determine it is
necessary.
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\54\ NERC has developed a Statement of Compliance Registry
Criteria that provides guidance on how NERC will identify
organizations that may be candidates for registration. See NERC
comments, Attachment B; NERC's February 6, 2007 supplemental filing.
---------------------------------------------------------------------------
88. California Cogeneration states that, while focusing on entities
that have a material impact on the Bulk-Power System is a possible
approach to applying the Reliability Standards, the proposed rule does
not define how ``material impact'' may be demonstrated. According to
California Cogeneration, material impact will vary among
Interconnections and it may vary among individual transmission systems.
Therefore, California Cogeneration states that the task of defining
``material impact'' should be remanded by the Commission to NERC for
resolution through an inclusive stakeholder process. Until that process
is completed, California Cogeneration maintains that the Reliability
Standards should not be finally adopted as mandatory and enforceable.
89. Various Georgia cities, which are all member systems of MEAG,
state that the Commission should place reasonable limits on the
applicability of the proposed Reliability Standards.\55\ Each maintains
that the Final Rule should include a rebuttable presumption that their
distribution system facilities have no material effect on Bulk-Power
System reliability unless established otherwise. They suggest that such
a rebuttable presumption approach would fairly establish the
``reasonable limits on applicability'' of the Reliability Standards
based on their respective sizes. Similarly, Small Entities Forum
supports a rebuttable presumption that any LSE or distribution provider
with less than 25 MW of load would be excluded unless a Regional Entity
decides that a reason exists to include it.
---------------------------------------------------------------------------
\55\ See NOPR at P 1175-76.
---------------------------------------------------------------------------
90. California Cogeneration states that qualifying facilities (QFs)
are exempted from section 215 of the FPA. It claims that, after passage
of EPAct 2005, the Commission modified its regulations to provide that
QFs are exempt from all sections of the FPA except sections 205, 206,
220, 221 and 222.\56\ Further, California Cogeneration states that the
[[Page 16427]]
Commission should set limits on whether a Reliability Standard
applicable to a generator owner or operator also applies to operators
of cogeneration facilities. According to California Cogeneration, the
Commission has clearly determined that the impact by a cogenerator on
the reliability of the system is limited to its net load on the
system.\57\ Therefore, California Cogeneration maintains that the
Reliability Standards should reflect this limitation.
---------------------------------------------------------------------------
\56\ 18 CFR 292.601(c).
\57\ California Cogenration at 6-7, citing California
Independent System Operator Corp., 96 FERC ] 63,015, at P 7, 24-25
(2001).
---------------------------------------------------------------------------
91. Finally, Small Entities Forum and Entergy state that, despite
the existence of a threshold in a particular Reliability Standard, the
ERO or a Regional Entity should be permitted to include an otherwise
exempt facility, on a facility-by-facility basis, if it determines that
the facility is needed for Bulk-Power System reliability. South
Carolina E&G states that exceptions to an exemption threshold should
sufficiently improve reliability so as to justify the administrative
costs and other burdens. However, SMA and MidAmerican oppose allowing
the ERO or its designee to include otherwise exempt facilities by
making exceptions.
ii. Commission Determination
92. The Commission believes that, at the outset of this new
program, it is important to have as much certainty and stability as
possible regarding which users, owners and operators of the Bulk-Power
System must comply with mandatory and enforceable Reliability
Standards. NERC, as the ERO, has developed an approach to accomplish
this through its compliance registry process. The Commission has
previously found NERC's compliance registry process to be 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.'' \58\
---------------------------------------------------------------------------
\58\ ERO Certification Order at P 689.
---------------------------------------------------------------------------
93. NERC has provided with its NOPR comments, and in a subsequent
supplemental filing, a Statement of Compliance Registry Criteria that
describes how NERC will identify organizations that may be candidates
for registration and assign them to the compliance registry. For
example, NERC plans to register only those distribution providers or
LSEs that have a peak load of 25 MW or greater and are directly
connected to the bulk electric system or are designated as a
responsibility entity as part of a required underfrequency load
shedding program or a required undervoltage load shedding program. For
generators, NERC plans to register individual units of 20 MVA or
greater that are directly connected to the bulk electric system,
generating plants with an aggregate rating of 75 MVA or greater, any
blackstart unit material to a restoration plan, or any generator
``regardless of size, that is material to the reliability of the Bulk-
Power System.''
94. The compliance registry identifies specific categories of
users, owners and operators that correlate to the types of entities
responsible for performing specific functions described in the NERC
Functional Model.\59\ These same functional types are also used by the
ERO to identify the entities responsible for compliance with a
particular Reliability Standard in the Applicability section of a given
standard. Thus, each registered entity will be registered under one or
more appropriate functional categories, and that registration by
function will determine with which Reliability Standards--and
Requirements of those Reliability Standards--the entity must comply. In
other words, a user, owner or operator of the Bulk-Power System would
be required to comply with each Reliability Standard that is applicable
to any one of the functional types for which it is registered.
---------------------------------------------------------------------------
\59\ The Statement of Compliance Registry Criteria, as well as
the Functional Model, identify, inter alia, the following functions:
Balancing authority, distribution provider, generator operator,
generator owner, load serving entity, planning authority,
purchasing-selling entity, transmission owner, transmission operator
and transmission service provider. An entity may be registered under
one or more of these functions.
---------------------------------------------------------------------------
95. We believe that NERC has set reasonable criteria for
registration and, thus, we approve the ERO's compliance registry
process as an appropriate approach to allow the ERO, Regional Entities
and, ultimately, the entities responsible for compliance with mandatory
Reliability Standards to know which entities are responsible for
initial implementation of and compliance with the new Reliability
Standards. Further, based on supplemental comments of APPA, TAPS and
NRECA, it appears that there is support among many of the smaller
entities for the NERC compliance registry process.\60\ Thus, at this
juncture, the Commission will rely on the NERC registration process to
identify the set of entities that are responsible for compliance with
particular Reliability Standards.
---------------------------------------------------------------------------
\60\ See Supplemental Comments of TAPS (February 13, 2007), APPA
(February 14, 2007), and NRECA (February 15, 2007).
---------------------------------------------------------------------------
96. In sum, the ERO will identify those entities that must comply
with Reliability Standards in three steps: (1) The ERO will identify
and register those entities that fall under its definition of bulk
electric system; (2) each registered entity will register in one or
more appropriate functional categories and (3) each registered entity
will comply with those Reliability Standards applicable to the
functional categories in which it is registered.
97. In response to MEAG's concern that the Commission previously
determined that it was not bound by the NERC compliance registry
process and that there thus was uncertainty, the Commission is
modifying the approach proposed in the NOPR and, as noted above, will
use the NERC compliance registry to determine those users, owners and
operators of the Bulk-Power System that must comply with the
Reliability Standards. Each individual Reliability Standard will then
identify the set of users, owners and operators of the Bulk-Power
System that must comply with that standard. While the Commission may
take prospective action against an entity that was not previously
identified as a user, owner or operator through the NERC registration
process once it has been added to the registry, the Commission will not
assess penalties against an entity that has not previously been put on
notice, through the NERC registration process, that it must comply with
particular Reliability Standards. Under this process, if there is an
entity that is not registered and NERC later discovers that the entity
should have been subject to the Reliability Standards, NERC has the
ability to add the entity, and possibly other entities of a similar
class, to the registration list and to direct corrective action by that
entity on a going-forward basis.\61\ The Commission believes that this
should prevent an entity from being subject to a penalty for violating
a Reliability Standard without prior notice that it must comply with
that Reliability Standard.
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\61\ See NERC Rules of Procedure, Sec. 500.
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98. As stated in the NOPR, NERC has indicated that in the future it
may add to a Reliability Standard limitations on applicability based on
electric facility characteristics such as generator nameplate
ratings.\62\ While the NOPR explored this approach as a means of
addressing concerns over applicability to smaller entities, the
Commission believes that, until the ERO submits a Reliability Standard
with such a
[[Page 16428]]
limitation to the Commission, the NERC compliance registry process is
the preferred method of determining the applicability of Reliability
Standards on an entity-by-entity basis.
---------------------------------------------------------------------------
\62\ NOPR at P 49.
---------------------------------------------------------------------------
99. A number of municipalities and generation owners ask that the
Commission review their particular circumstances and provide an
individual waiver from compliance with the mandatory Reliability
Standards. In light of our above discussion, the Commission declines to
determine whether any individual municipality, generation owner or
other entity is subject to a specific Reliability Standard. Rather,
NERC and the Regional Entities should determine such applicability in
the first instance through the registration process.
100. We agree with California Cogeneration that the Commission's
regulations currently exempt most QFs from specific provisions of the
FPA including section 215.\63\ The Commission is concerned, however,
whether it is appropriate to grant QFs a complete exemption from
compliance with Reliability Standards that apply to other generator
owners and operators. It is not clear to the Commission that for
reliability purposes there is a meaningful distinction between QF and
non-QF generators. While such an issue is beyond the scope of the
current rulemaking, we note that, concurrent with the issuance of this
Final Rule, the Commission is issuing a notice of proposed rulemaking
that proposes to amend the Commission's regulation that exempts most
QFs from section 215 of the FPA.
---------------------------------------------------------------------------
\63\ 18 CFR 292.601(c).
---------------------------------------------------------------------------
101. Finally, the Commission agrees that, despite the existence of
a voltage or demand threshold for a particular Reliability Standard,
the ERO or Regional Entity should be permitted to include an otherwise
exempt facility on a facility-by-facility basis if it determines that
the facility is needed for Bulk-Power System reliability.\64\ However,
we note that an entity that disagrees with NERC's determination to
place it in the compliance registry may submit a challenge in writing
to NERC and, if still not satisfied, may lodge an appeal with the
Commission.\65\ Therefore, a small entity may appeal to the Commission
if it believes it should not be required to comply with the Reliability
Standards.
---------------------------------------------------------------------------
\64\ Demand resources deemed critical by the ERO to Bulk-Power
System reliability should be included in the registry.
\65\ See ERO Certification Order at P679.
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b. Ability To Accept Compliance on Behalf of Members
i. Comments
102. APPA, NERC, ELCON, APPA, TAPS and Small Entities Forum support
the Commission's proposal to allow a joint action agency, generation
and transmission (G&T) cooperative, or other entities to accept
responsibility for compliance with Reliability Standards on behalf of
their members and also may divide the responsibilities for compliance
with its members. APPA states that this should also be extended to
RTOs, vertically integrated utilities, and other wholesale power
suppliers that perform substantial reliability functions on behalf of
their full requirements wholesale customers, including public power
distribution systems and other entities that currently fulfill
reliability functions for customers. APPA, TAPS and Small Entities
Forum state that the procedure should allow for this responsibility to
be assigned on a standard-by-standard basis.
103. In response to the Commission's proposal to direct NERC to
develop procedures that permit a joint action agency or similar
organization to accept compliance responsibility on behalf of its
members, NERC proposes the following procedure, and has updated its
entity registration criteria to reflect these changes.\66\ NERC states
that each ``central'' organization should be able to register as being
responsible for compliance for itself and collectively on behalf of its
members. Each member within a central organization may separately
register to be accountable for a particular reliability function
defined by the standards. Under NERC's proposal, if the central
organization and a member organization cannot agree that one
organization or the other is responsible, or if the parties agree that
the responsibilities for a particular reliability function should be
split, then NERC would register both entities concurrently. NERC and
the Regional Entities will then have the authority to find either
organization or both accountable for a violation of a Reliability
Standard, based on the facts of the case and circumstances surrounding
the violation.
---------------------------------------------------------------------------
\66\ See NERC comments at 53-55; NERC supplemental filing,
Statement of Compliance Registry Criteria (Revision 3) at 9.
---------------------------------------------------------------------------
104. AMP-Ohio states that the Commission should clarify that a
joint action agency should not be required to assume compliance
responsibility for its members for all reliability-related functions.
It asks that the Commission allow flexibility in how joint action
agencies and their members allocate responsibility. TAPS states that
joint action agencies should be allowed to achieve compliance with a
standard at the joint action agency level rather than to simply stand
in the shoes of their individual members. TAPS states that this is
necessary to ensure comparable treatment for small entities in relation
to large utilities. Where a joint action agency accepts compliance
responsibility and a standard is susceptible to joint action agency-
level assessment of compliance, the Commission should ask NERC to adopt
such assessment to avoid an adverse impact on competition.
105. MEAG finds the Commission's proposal with regard to joint
action agencies problematic. MEAG asserts that the proxy approach is
not a universal approach to small municipal systems. For example, this
option would be fundamentally inconsistent with MEAG's role as a G&T
cooperative serving its member systems because MEAG has no authority to
plan, physically operate, modify, maintain or test the local
distribution system facilities of the member systems. Second, MEAG
states that if it were to assume the role of the proxy compliance agent
for the member systems and incur a fine for the failure of a few to
comply with the requirements of the Reliability Standards, then the
imposition of fines would lead to a rate increase to all systems, an
improper and unjustifiable cost shifts among the member systems. Third,
if MEAG were to err in its role as a proxy compliance agent for the
member systems, MEAG could be sued and there is nothing that presently
limits its liability or provides indemnification to MEAG in that
circumstance. Moreover, MEAG states that the compliance-by-proxy option
will not mitigate the economic impact on many small distribution-only
entities because many are not members of joint action agencies.
106. Several commenters, including EEI, PJM and FirstEnergy do not
oppose the Commission's proposal to allow organizations to accept
compliance responsibility on behalf of members so long as compliance
responsibility is clear and responsible entities are held accountable.
FirstEnergy and PJM state that some Reliability Standards appear to
have duplicate accountability in different organizational entities,
which could create confusion and complicate operational authority and
thus undermine the transmission operator chain of command required to
respond quickly and decisively to system operational events. Further,
FirstEnergy
[[Page 16429]]
states that some Reliability Standards obligate an entity to perform
reliability functions when that entity may not be able to perform its
reliability function due to other legal constraints. FirstEnergy states
that one effective approach to resolving this problem would be to
establish a ``priority'' of control between entities. FirstEnergy adds
that entities that are subject to legal control by ISOs and RTOs should
be afforded a ``safe harbor'' under the Reliability Standards if,
during an emergency, they perform as directed by the ISO or RTO,
whether under the ISO/RTO's OATT or under the ISO/RTO's authority as
reliability coordinator.
ii. Commission Determination
107. The Commission directs the ERO to file procedures which permit
(but do not require) an organization, such as a joint action agency,
G&T cooperative or similar organization to accept compliance
responsibility on behalf of its members. The Commission believes that
NERC's proposed procedures described above are reasonable, and directs
the ERO to submit a filing within 60 days.\67\ In allowing a joint
action agency, G&T cooperative or similar organization to accept
compliance responsibility on behalf of its members, our intent is not
to change existing contracts, agreements or other understandings as to
who is responsible for a particular function under a Reliability
Standard. Further, we clarify that there should not be overlaps in
responsibility nor should there be any gaps.
---------------------------------------------------------------------------
\67\ Section 39.10(b) of the Commission's regulations, 18 CFR
39.10(b), provides that the Commission, upon its own motion or upon
complaint, may propose a change to an ERO or Regional Entity Rule.
---------------------------------------------------------------------------
108. In response to concerns raised by AMP-Ohio and MEAG, the
Commission clarifies that an organization is not required to assume
compliance responsibility for its members for any reliability-related
functions and all Reliability Standards. Moreover, under NERC's
proposal, a member within a central organization may separately
register to be accountable for a particular reliability function so the
responsibility for reliability functions can be split. The Commission
believes that this will provide flexibility and will not require an
entity to assume responsibility where it is not possible to do so. We
also believe that NERC's proposal adequately addresses TAPS' concern
that a joint action agency should be allowed to achieve compliance at
the joint action agency level. Specifically, the Statement of
Compliance Registry Criteria provides that a central organization can
register for all functions that it performs itself and, in addition,
may register on behalf of one or more of its members for functions for
which the member would otherwise be required to register.\68\
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\68\ See NERC Supplemental Filing, Statement of Compliance
Registry Criteria (Revision 3), at 8-9.
---------------------------------------------------------------------------
109. NERC, in developing its procedures relating to joint action
agencies and similar organizations, should consider the concerns of
EEI, PJM and FirstEnergy regarding the need for ensuring clear lines of
responsibility. While we agree with FirstEnergy in the abstract that an
entity implementing the legal directives of an ISO or RTO should not be
penalized for following an ISO or RTO directive during an emergency, we
will not mandate a safe harbor provision for such circumstances.
Rather, these and other matters should be considered by the ERO or a
Regional Entity when deciding the appropriate enforcement action in
response to an event where a violation of a Reliability Standard may
have occurred.
3. Definition of User of the Bulk-Power System
110. In the NOPR, the Commission did not propose a generic
definition of the term ``User of the Bulk-Power System.'' Rather, the
Commission stated that it would determine applicability on a standard-
by-standard basis.\69\ The NOPR explained that Sec. 40.1(b) of the
proposed regulations would require the ERO to 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, which is NERC's current practice. The NOPR also stated
that entities concerned that a particular proposed Reliability Standard
would apply more broadly than the statute allows may raise their
concerns in the context of the specific Reliability Standard.
---------------------------------------------------------------------------
\69\ NOPR at P 43.
---------------------------------------------------------------------------
a. Comments
111. APPA disagrees with a standard-by-standard approach to
defining the term ``user of the Bulk-Power System'' because it would go
beyond those facilities that are required to maintain the reliability
of the high-voltage, bulk transmission system and intrude into state
and local matters and trespass on state jurisdiction. According to
APPA, the Reliability Standards themselves state their applicability in
terms of the Functional Model, which does not include size limitations
in the various functional categories included in it. Without some type
of outer limit on the ``user of the Bulk-Power System'' definition, all
such entities regardless of size or their impact on the Bulk-Power
System, must review every proposed Reliability Standard and protest
every time they have a ``concern in the context of the specific
Reliability Standard.'' They must also retain permanent staff or
consultants to evaluate new or revised standards. Rather, APPA, as does
TANC, urges the Commission to support NERC's registry criteria to make
the definition of ``users of the Bulk-Power System'' co-extensive with
the users on NERC's compliance registry.
112. SMA is concerned that not specifically defining who is a
``user of the Bulk-Power System'' will not provide timely notice to
entities that are not the parties historically responsible for
implementing NERC's prior reliability standards. SMA states that NERC
must identify the subset of users that must comply with any given
Reliability Standard at a sufficiently early stage for all such
affected parties to have an opportunity to raise objections to the
sweep or content of the Reliability Standard while approval of that
Reliability Standard is under consideration. SMA also argues that
NERC's Rules of Procedure must require actual notice to an entity
before it is placed on the compliance registry.
113. Southwest TDUs urges the Commission to clarify that ``users''
are entities that have more involvement with it than merely receiving
power from it. Since these Reliability Standards will become mandatory
and violation of any of them can be accompanied by economically
significant penalties, Southwest TDUs urges the Commission to make
every effort to be specific about what constitutes a ``user.''
114. California Cogeneration states that the Commission has not
provided any detail as to how a ``user'' will be identified. The NOPR
and the NERC Reliability Standards it proposes to adopt rely on the
broad entities identified in the NERC Functional Model. According to
California Cogeneration, using only the NERC Functional Model provides
no detail and no differentiation in the applicability of each
Reliability Standard. While a single definition of ``user'' may not be
appropriate, California Cogeneration maintains that using only the
fixed designations within the NERC Functional Model does not provide
sufficient specificity. The terms ``Generator Owner'' and ``Generation
Operator'' also must be qualified so that they only apply to generation
operations that utilize the grid and exclude
[[Page 16430]]
generation output dedicated to on-site consumption.
b. Commission Determination
115. The Commission's determination above to rely on the ERO's
compliance registry process to identify users, owners and operators of
the Bulk-Power System that must comply with new mandatory and
enforceable Reliability Standards should resolve the concerns expressed
by APPA, SMA and others regarding the need to identify and provide
timely notice to those users of the Bulk-Power System that are expected
to comply with specific Reliability Standards.
116. While we recognize the desire of some commenters for a
concise, generic definition of ``user of the Bulk-Power System,'' we
are concerned that any attempt to define the term at this time will
either be overly broad so as not to provide any helpful guidance or
overly narrow so as to exclude entities that should be covered. The
Commission believes that it has employed a reasonable approach by
endorsing NERC's compliance registry process and requiring that each
Reliability Standard identify the subset of users, owners and operators
to whom that particular Reliability Standard applies.
4. Use of the NERC Functional Model
117. NERC has developed a ``Functional Model'' that defines the set
of functions that must be performed to ensure the reliability of the
Bulk-Power System. The Functional Model identifies 14 functions and the
name of a corresponding entity responsible for fulfilling each
function.
118. In the NOPR, the Commission proposed to use the NERC
Functional Model to identify the applicable entities to which each
Reliability Standard applies.\70\ The Commission explained that
focusing on the functions an entity performs to identify what entities
are users, owners and operators of the Bulk-Power System, and thus what
entities are subject to the Reliability Standards, provides a useful
level of detail and appears to be more practical than simply
identifying an applicable entity as a user, owner or operator. In
addition, the NOPR recognized concerns that the Functional Model may
contain ambiguities and proposed to require NERC to specifically
address these concerns.
---------------------------------------------------------------------------
\70\ NOPR at P 46-48.
---------------------------------------------------------------------------
119. The Commission proposed that, because the Functional Model is
linked to applicability of the Reliability Standards, the ERO should
submit for Commission approval any future modifications to the
Functional Model that may affect the applicability of the Reliability
Standards.
a. Filing the Functional Model With the Commission
i. Comments
120. NERC states that, while it believes that the Functional Model
should be filed for informational purposes only, it will submit any
changes to the Functional Model to the Commission for approval as
requested. While NERC states that the Functional Model will not
function as a legally binding document like a Reliability Standard, the
Commission's approval of this reference document and of any changes to
the Functional Model will support the development of high quality,
enforceable and technically sufficient standards.
121. Several commenters, including NERC, EEI, APPA, MidAmerican,
National Grid and MRO state that the Functional Model is not part of
the Reliability Standards and should be filed with the Commission for
informational purposes only. They generally state that the Functional
Model is not a definitive guide to the ``users, owners and operators''
of the Bulk-Power System and should not be used to establish
obligations under section 215, which should be established within each
individual Commission-approved Reliability Standard.
122. Northeast Utilities is concerned with the Commission's
proposal to use the NERC Functional Model to identify applicable
entities. It believes that the Functional Model can be useful in
drafting standards, but it is not a substitute for having clear
definitions of the entities responsible for compliance with the
requirements for each Reliability Standard within a region. The
entities responsible for meeting the standard may vary depending on how
the Bulk-Power System is operated. FirstEnergy states that the
Functional Model may not clearly or correctly identify the entities to
which a Reliability Standard applies and maintains that the Functional
Model should be applied only where all of the affected stakeholders
agree on the final classifications of each Registered Entity's roles
and responsibilities.
123. In contrast, TANC and ISO-NE state that the Commission should
require that any future modification to the Functional Model that could
affect the categories of entities that must comply with a particular
Reliability Standard be approved by the Commission because the
Functional Model is so closely interrelated with the applicability of
each Reliability Standard.
124. APPA, TAPS and ReliabilityFirst maintain that any modification
to the NERC Functional Model should be reviewed and approved through
the Reliability Standards development process. According to
ReliabilityFirst, any change to the Functional Model is essentially an
amendment to the Reliability Standard made outside the ERO process.
TANC asserts that a Reliability Standard will only be complete if the
definitions of the Functional Model are developed through the
Reliability Standards development process just like any Reliability
Standard. APPA would allow NERC to issue interpretations of the
Functional Model, but these interpretations should then be confirmed
through NERC procedures.
125. TAPS cautions that, because the Functional Model includes no
express size limitations, NERC and the Commission can rely on the
Functional Model to define applicability of standards only if such
limits are imposed by NERC's compliance registry criteria and its bulk
electric system definition. The Small Entities Forum is concerned
because smaller entities have historically performed only a subset of
functions. For example, it states that some joint action agencies
invest in transmission facilities that are operated by others, but that
these joint action agencies, under the Functional Model, would have to
verify that these facilities, operated by others, are being operated
and maintained according to applicable Reliability Standards.
126. Several commenters argue that the Functional Model contains a
number of ambiguities. MISO argues that the definition of the term
planning coordinator is circular and may lead to one subset of the
transmission system having multiple Planning Coordinators. MISO
recommends that the Commission direct NERC to survey the industry to
identify the planning roles that actually exist in the industry and
clarify the role of the wide-area Planning Coordinator. MISO and
Wisconsin Electric note that the proposed Reliability Standards do not
specify who fulfills the Interchange Authority or Planning Authority
roles, and there is no common industry understanding of those roles.
Finally, California Cogeneration states that the definition of LSE is
too inclusive and should be modified to exclude entities providing
service only to loads on-site or pursuant to private contract.
[[Page 16431]]
ii. Commission Determination
127. The Commission accepts the characterization offered by
numerous commenters that the Functional Model is an evolving guidance
document that is not intended to convey firm rights and
responsibilities. Further, we agree that the applicability section of a
particular Reliability Standard should be the ultimate determinant of
applicability of each Reliability Standard. In light of this, we will
not require the ERO to submit revisions of the Functional Model for
Commission approval. While some commenters suggest that revisions be
filed for informational purposes, we see little value in mandating such
a filing.\71\
---------------------------------------------------------------------------
\71\ We note that NERC has available on its Web site, http://www/nerc.com
, the current version of the Functional Model. We expect
NERC to continue to do so in the future.
---------------------------------------------------------------------------
128. With regard to the comments of TAPS, APPA, TANC and others on
whether revisions to the Functional Model should be made through the
ERO's Reliability Standards development process, we do not believe that
it is necessary under the statute, since applicability will be
determined at this time by the specifications of the Reliability
Standards and the compliance registry process. Thus, we leave to the
discretion of the ERO the appropriate means of allowing stakeholder
input when revising the Functional Model. To the extent that changes in
the Functional Model require revised specification in the Reliability
Standards, the latter will be addressed in the Reliability Standards
development process.
129. While TAPS and Small Entities Forum raise concerns regarding
the absence of size limitations in the Functional Model and potential
negative impacts on small entities, we believe that these concerns are
addressed above in our decision regarding use of the NERC compliance
registry process. MISO, Wisconsin Electric and others comment on the
need to clarify certain ambiguities in the Functional Model. Given that
the Functional Model is an evolving guidance document, the ERO can
address such concerns as it updates and revises the Functional Model.
b. Responsibility for Functions Within the Functional Model
130. In the NOPR, the Commission explained that, in the context of
an ISO or RTO or any organization that pools resources, decision-making
and implementation are performed by separate groups.\72\ The ISO or RTO
typically makes decisions for the transmission operator and, to a
lesser extent, the generation operator, while actual implementation is
performed by either local transmission control centers or independent
generation control centers. The NOPR proposed 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.'' \73\
---------------------------------------------------------------------------
\72\ NOPR at P 236.
\73\ Id. at P 237. Although discussed in the context of the
communication (COM) Reliability Standards, the NOPR suggested that
the proposal would apply to other Reliability Standards. Because of
the nature of the comments on the issue and its relationship to the
Functional Model, we discuss the matter here.
---------------------------------------------------------------------------
i. Comments
131. A number of commenters raise concerns or seek clarification
regarding the relationship between the Functional Model and existing
agreements that set forth the responsibility of various entities,
particularly in the context of ISO and RTO operations. MISO requests
the Commission to clarify that nothing in the Functional Model requires
one entity to be responsible for all of the tasks within a function,
regardless of who actually performs the task. In those ISOs and RTOs
where balancing authorities have retained and have never delegated to
the RTO certain tasks that fall within the balancing authority
function, NERC's Functional Model should only require one responsible
entity per task rather than one responsible entity for all of the tasks
within that function. MISO submits that the NERC Functional Model
should not play a prescriptive role by assigning responsibility for a
given task where such an assignment would be inconsistent with a
Commission-approved regional transmission agreement, RTO tariff, or
reliability plan filed with NERC, all of which specify the entity
performing each task.
132. PJM states that, while the Commission proposed to assign
responsibility for reliable operations to multiple entities within an
ISO or RTO to address its concern that decision making and
implementation are performed by separate organizations, it does not
believe that increasing the number of organizations responsible for a
given function for the same facilities within the bulk electric system
has been shown to be an effective or appropriate solution to the
concerns cited. PJM states that NERC employs processes that
successfully manage the delegation of operational tasks while
maintaining single entity accountability for the reliable performance
of those operational tasks.
133. ATC states that Regional Entities should be given the
flexibility to allow some ``tasks'' within a ``function'' to be
performed by one entity, with the remaining tasks to be performed by
another entity. According to ATC, this would provide entities--
particularly smaller ones--with the flexibility to transfer their
responsibility for a reliability task or function to another registered
entity that can perform the work more effectively. Further, ATC
maintains, Regional Entities should ensure that entities be given
accountability only for systems, facilities and functions over which
they actually have control.
134. NPCC states that requirements applicable to local control
centers should be distinct from requirements applicable to transmission
and generation operators under the NERC Functional Model. NPCC submits
that there is a difference between being assigned to do a task and
being responsible for the completion of that task. An organization that
registers with NERC as performing a function is considered a
responsible entity and must ensure that all tasks are performed. While
an organization may delegate a task to another organization, it may not
delegate its responsibility for ensuring that the task is accomplished.
135. According to Ontario IESO, the Commission's proposal is
inconsistent with the NERC Functional Model, which envisions one
responsible entity for each reliability function. In contrast, the
Commission's proposal would split the same function between different
organizations such as an ISO and a local control center. PJM claims
that, under the Functional Model, single entity registration is a
foundational cornerstone for ensuring clear responsibility and
accountability for compliance with Reliability Standards.
136. Ontario IESO asserts that the Commission's proposal is also
problematic because in the event of a violation it will be difficult to
determine who violated the Reliability Standard--the entity making the
decision or the entity implementing the decision. Ontario IESO argues
that, although the NERC Functional Model is not foolproof, it avoids
complications by distinguishing between responsibility and performance.
The ISO is the responsible entity and it delegates some of its tasks to
local control centers, but retains the overall responsibility.
137. According to Ontario IESO, NERC has recognized that, although
[[Page 16432]]
organizations such as local control centers play an important role in
reliability, they are not responsible entities. Therefore, NERC has
made such organizations subject to compliance audits and placed other
requirements on them. In addition, NERC intends that the regional
reliability plans will document the relationships between the local
control centers and the entity that delegates its responsibility to
such centers. The current framework has a mechanism for accommodating
reliability considerations for organizations such as local control
centers. In this regard, NERC's ongoing formal certification of
reliability coordinator, balancing authority and transmission provider
will be useful in determining any delegation of tasks to local control
centers that must take place for a clear demarcation of
responsibilities. Ontario IESO advises that, since NERC has not
finished this task, the Commission should defer its decision in this
regard.
138. ISO/RTO Council states that the Commission should not use the
term ``local control center'' because it will cause confusion. The NERC
Functional Model does not define the term and it means different things
in different regions. For example, in MISO, which consists of 25
balancing areas, ``local control center'' is an equivalent term for
balancing area although this was probably not the Commission's intent
in the NOPR. Therefore, ISO/RTO Council argues that the Reliability
Standards should be limited to defining the tasks in the context of
users, owners and operators of the Bulk-Power System; any delegation of
responsibilities to a local control center or any other organization
should take place in the context of ISO/RTO governing documents,
operating agreements, tariffs and other arrangements with transmission
owners and related stakeholders. This approach, according to ISO/RTO
Council will address the Commission's concerns with respect to local
control centers without preempting possible regional solutions.
139. FirstEnergy believes that, while independent authority to
operate the transmission system should be self-evident, in RTO
environments with local control centers, the tasks performed by each
entity do not encompass the entirety of tasks performed by the
transmission operator under the Functional Model. It suggests that NERC
should revise the Functional Model to create certification and
registration requirements for local control authorities within RTOs
that perform real-time operations of the transmission system.
FirstEnergy states that a revised NERC Functional Model should
recognize local control centers that take some direction from RTOs yet
maintain authority to act independently to carry-out functional tasks
that require real-time operation of the system. According to
FirstEnergy, the required registration and certification of such
entities would clearly indicate the need for operational personnel in
these control rooms to be NERC-certified. It concludes that at a
minimum, a NERC certification for the tasks performed by such local
control center individuals would be an enhancement over the current
situation.
140. ISO-NE argues that the Commission should not mandate that the
tasks performed by local control centers be included in the definition
of transmission operator because to do so would be to suggest that a
local control center has independent autonomy in operating the Bulk
Power System which would conflict with the ``one set of hands on the
wheel'' philosophy. It explains that local control center personnel in
New England implement tasks delegated to them by ISO-NE for operation
of designated transmission facilities. Therefore, ISO-NE submits, the
scope of the Reliability Standard need not be expanded.
ii. Commission Determination
141. In response to the many concerns of commenters, the Commission
clarifies that it did not intend to change existing contracts, impose
new organizational structures or otherwise affect existing agreements
that set forth the responsibilities of various entities. Rather, its
intent was to allow enough granularity in the definitions so that the
appropriate user, owner or operator of the Bulk-Power System would be
identified for each Reliability Standard. We agree also with MISO's
statement that nothing in the Functional Model requires one entity to
be responsible for all of the tasks within a function, regardless of
who actually performs the task.
142. The Commission's concern is that, particularly in the ISO, RTO
and pooled resource context, there should be neither unintended
redundancy nor gaps for responsibilities within a function. In
particular, the Commission is concerned that such ``gaps'' could occur
in the context of several Reliability Standards addressing matters
related to activities other than directing or implementing real-time
operations.\74\ For example, the involvement of a transmission operator
at an ISO or RTO with respect to the requirements related to
telecommunications facilities (COM-001-1) from the local control room
and blackstart restoration plans (EOP-005-0) may be minimal. Because
the operators at local control centers actually perform all or most of
the tasks contemplated under various Reliability Standards, we are
concerned that there may be unintended gaps in such responsibilities if
the existing contracts between the ISO or RTO and owners of the
facilities do not address such responsibilities.
---------------------------------------------------------------------------
\74\ See, e.g., CIP-001--Sabotage Reporting; COM-001--
Telecommunications; EOP-003--Load Shedding Plans; EOP-004--
Disturbance Reporting; EOP-005--System Restoration Plans; EOP-008--
Plans for Loss of Control Center Functionality; PRC-001--System
Protection Coordination; PRC-007--Assessing Consistency with Entity
Underfrequency Load Shedding Programs with Regional Reliability
Organizations UFLS Program Requirements; PRC-009--Analysis and
Documentation of Underfrequency Load Shedding Performance Following
an Underfrequency Event; PRC-010--Technical Assessment of the Design
and Effectiveness of Undervoltage Load Shedding Program; PRC-022--
UFLS Program Performance; and TOP-006--Monitoring System Conditions.
---------------------------------------------------------------------------
143. In response to MISO, we did not intend to be prescriptive in
assigning tasks to specific entities. The intent was to allow
flexibility in identifying the actual user, owner or operator of the
Bulk-Power System that would be responsible for complying with the
Requirements in the Reliability Standards. One approach could be that
the RTO, ISO or other pooled resource registers as the transmission
operator pursuant to the NERC compliance registry process and, while
retaining ultimate responsibility, assigns specific tasks to be
performed by what are sometimes known as local control centers or other
relevant organizations. Alternatively, the local control center
operators could register together with the RTO, ISO or pooled resources
as transmission operators clearly delineating their specific
responsibilities with regard to the Requirements of particular
Reliability Standards. Such joint registration must assure that there
is no overlap between the decisionmaking and implementation functions,
i.e., that there are not two sets of hands on the wheel. Again, our
intent is to ensure that there is neither redundancy nor gap in
responsibility for compliance with the Requirements of a Reliability
Standard, while allowing entities flexibility to determine how best to
accomplish this goal.
144. Consistent with our above explanation, we agree with NPCC that
there is a difference between being assigned to perform a task and
being responsible for completing the task. The organization that
registers with NERC to perform a function will be the
[[Page 16433]]
responsible entity and, while it may delegate the performance of that
task to another, it may not delegate its responsibility for ensuring
the task is completed.
145. Accordingly, the Commission directs that the ERO, in
registering RTOs, ISOs and pooled resource organizations (or, indeed in
registering any entity), assure that there is clarity in the assigning
responsibility and that there are no gaps or unnecessary redundancies
with regard to the entity or entities responsible for compliance with
the Requirements of each relevant Reliability Standard. Accordingly,
although the Commission is not requiring NERC to amend the Functional
Model, we believe our concerns can be addressed by having the ERO,
through its compliance registry process, ensure that each user, owner
and operator of the Bulk-Power System is registered for each
Requirement in the Reliability Standards that relate to transmission
owners to assure there are no gaps in coverage of the type discussed
here.
5. Regional Reliability Organizations
146. The NOPR stated that 28 proposed Reliability Standards would
apply, in whole or in part, to a regional reliability organization.\75\
Further, many of the proposed Reliability Standards that have
compliance measures refer to the regional reliability organization as a
compliance monitor. The Commission stated in the NOPR that it was not
persuaded that a regional reliability organization's compliance with a
Reliability Standard can be enforced as proposed by NERC because it
does not appear that a regional reliability organization is a user,
owner or operator of the Bulk-Power System.
---------------------------------------------------------------------------
\75\ NOPR at P 54.
---------------------------------------------------------------------------
147. The Commission proposed to approve and direct modification of
five Reliability Standards that apply partially to regional reliability
organizations. For the other Reliability Standards that apply to
regional reliability organizations, the Commission proposed, as an
interim measure, 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 information
related to data gathering, data maintenance, reliability assessments
and other process-type functions. The NOPR explained that this approach
is necessary to ensure that there will be no gap during the transition
from the current voluntary system to a mandatory system in which
Reliability Standards are enforced by the ERO and Regional Entities.
The NOPR proposed that, in the long run, Regional Entities should be
made responsible, through delegation from the ERO, for the functions
currently performed by the regional reliability organizations. To
implement this, the Commission proposed the modification of delegation
agreements to require the Regional Entities to assume responsibility
for noncompliance. In addition, the Commission proposed that the
Reliability Standards should be modified to apply to the users, owners
and operators of the Bulk-Power System that are responsible for
providing information. The Commission proposed 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.
148. The Commission stated that, 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, the Commission does not
understand why, once the transition is complete, a regional reliability
organization should play a role separate from a Regional Entity whose
function and responsibility is explicitly recognized by section 215 of
the FPA. The Commission sought 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.
a. Comments
149. NERC believes it can remove references to regional reliability
organizations and Regional Entities from the Reliability Standards,
with the exception of retaining the Regional Entities as the compliance
enforcement authorities. However, NERC and California PUC request that
the Commission reconsider its proposal to direct that the ERO be listed
as the compliance monitor in each Reliability Standard. California PUC
states that naming NERC as the compliance monitor deprives the Regional
Entities of their enforcement role under section 215. NERC believes it
will be clearer, and consistent with the delegation agreements, to
designate the Regional Entity as the compliance monitor in almost all
Reliability Standards. According to NERC, this would also be helpful to
distinguish those few Reliability Standards that are monitored directly
by NERC.
150. ReliabilityFirst, TANC and SoCal Edison agree with the
Commission that regional reliability organizations and Regional
Entities cannot be users, owners or operators of the Bulk-Power System
and should not be subject to compliance with Reliability Standards.
TANC states that Reliability Standards that reference a regional
reliability organization need to be revised to reference a user, owner
or operator of the Bulk-Power System in order to comply with the
statute.
151. EEI agrees with the Commission's proposal to direct the ERO to
require users, owners and operators to provide the information related
to data gathering, data maintenance, reliability assessments and other
process-type functions that previously have applied to regional
reliability organizations. EEI also agrees that, in the long run, it is
appropriate to make the Regional Entities responsible through
delegation from the ERO for various functions now performed by regional
reliability organizations. In doing so, and during the transition in
particular, EEI maintains that it is important that functions now
performed by the regional councils, such as planning, be continued.
152. A number of commenters discuss the possible ongoing role for a
regional reliability organization. For example, Ontario IESO, NPCC and
National Grid state that the Commission should recognize that the
regional reliability organizations will continue to play a role in
areas including developing regional reliability plans and adequacy
requirements that are outside the jurisdiction of the ERO. NPCC states
that enforcement of adequacy requirements should continue to reside
with the regional reliability organization. National Grid states that
the role of regional reliability organizations can be preserved in a
variety of ways, including requiring obligations currently imposed upon
regional reliability organizations to be included in the regional
delegation agreements.
153. NPCC further maintains that regional reliability organizations
should continue to function as regional sites for technical expertise
for enhanced reliability requirements through adopting regionally-
specific criteria. According to NPCC, eliminating the ability for
regions to develop and propose new criteria that enhance system
reliability would edge the system closer towards the lowest common
denominator rather than striving towards operational excellence.
Further, Ontario IESO and NPCC state that regional reliability
organizations
[[Page 16434]]
should be allowed to perform certain functions for their members, such
as system operator workshops, forums for coordination of operations and
planning and operational readiness conference calls.
154. Massachusetts DTE comments that a regional reliability
organization should be allowed to propose a Reliability Standard that
may exceed or enhance the proposed mandatory Reliability Standards to
ensure regional reliability. It further states that any regional
reliability criteria proposed by a regional reliability organization
should be vetted through a regional stakeholder process and then
specifically adopted by the appropriate state regulatory authorities.
155. Although MRO does not oppose regional reliability
organizations, with regard to establishing and enforcing mandatory
Reliability Standards, MRO, Constellation and Xcel state that there is
no need to maintain a separate role for regional reliability
organizations. Because Regional Entities may perform non-reliability
functions, Constellation states that maintaining regional reliability
organizations will result in unnecessary cost. While Constellation has
no objection to the Regional Entities performing non-statutory
functions, it states that the Commission should not allow Regional
Entities to impose Reliability Standards developed by the regional
reliability organizations as mandatory Reliability Standards.
156. MidAmerican believes that it will be important to separate the
compliance functions of the Regional Entities from non-compliance
functions currently assigned to the regional reliability organizations.
It states that this can be done by: (1) Separating these functions
internally in the Regional Entities; (2) separating these functions in
different organizations; or (3) separating these functions by assigning
non-compliance related functions currently assigned to the regional
reliability organizations to other users, owners and operators. This
will minimize conflicts between the Regional Entity core compliance
function and the non-compliance regional reliability organization
requirements.
b. Commission Determination
157. The Commission adopts the NOPR proposal to eliminate
references to the regional reliability organization as a responsible
entity in the Reliability Standards. We conclude that this approach is
appropriate because, as explained in the NOPR, such entities are not
users, owners or operators of the Bulk-Power System. NERC indicates
that it can remove such references, except that the Regional Entity
should be identified as the compliance monitor where appropriate. While
the Commission originally proposed that the ERO should be designated as
the compliance monitor, we agree with NERC's approach and believe that
identifying the Regional Entity as the compliance monitor will provide
useful specificity as to which entity will be immediately tasked with
monitoring compliance with a particular Reliability Standard. However,
as we stated in Order No. 672, the ERO retains responsibility to ensure
that a Regional Entity implements its enforcement program in a
consistent manner, and to periodically review the Regional Entity's
enforcement activities.\76\
---------------------------------------------------------------------------
\76\ Order No. 672 at P 654.
---------------------------------------------------------------------------
158. For those Reliability Standards that identify the regional
reliability organization as the sole applicable entity, and that relate
to data gathering, data maintenance, reliability assessments and other
process-type functions,\77\ the NOPR proposed:
---------------------------------------------------------------------------
\77\ 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.
as an interim measure * * * 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 related to data gathering, data
maintenance, reliability assessments and other ``process''-type
functions. 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.\78\
---------------------------------------------------------------------------
\78\ NOPR at P 57 (footnotes omitted).
159. We continue to believe that this is a reasonable interim
measure, and note that EEI and others support this approach. To ensure
that the ERO properly and timely addresses this matter, we direct the
ERO to submit an informational filing within 90 days of the Final Rule
that describes its plan and schedule for developing both an interim and
long-term resolution based upon the above direction.
160. In response to the Commission's inquiry in the NOPR,
commenters identify a number of possible continuing roles for regional
reliability organizations. Such activities are beyond the scope of this
proceeding. Clearly, any such role must be limited to non-statutory
functions. Some commenters suggest that regional reliability
organizations may have a role in developing voluntary criteria.
Regional reliability organizations should not develop voluntary
criteria that address the same or similar matters as mandatory and
enforceable Reliability Standards, because that is the responsibility
of the Regional Entities.\79\
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\79\ See ERO Certification Order at P 281.
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D. Mandatory Reliability Standards
1. Legal Standard for Approval of Reliability Standards
161. The NOPR explained that section 215(d)(2) of the FPA states
that the Commission may approve a Reliability Standard if it determines
that it is just, reasonable, not unduly discriminatory or preferential
and in the public interest. Further, Order No. 672 laid out a series of
factors it would consider when assessing whether to approve or remand a
Reliability Standard.\80\
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\80\ Order No. 672 at P 262, 321-37.
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162. In response to NERC's suggestion that a proposed Reliability
Standard developed through its open and inclusive process is assured to
be ``just, reasonable, and not unduly discriminatory or preferential,''
the NOPR explained that:
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.\81\
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\81\ NOPR at P 74.
163. Further, with regard to NERC's ``benchmarks'' for evaluating a
proposed Reliability Standard,\82\ the Commission explained that it
would not be constrained by such benchmarks in approving or remanding a
proposed Reliability Standard. Rather, Order No. 672 identified factors
that the Commission will consider when determining whether a proposed
[[Page 16435]]
Reliability Standard satisfies the statutory requirements.
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\82\ Id. at P 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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a. Comments
164. NERC states that 83 of the Reliability Standards are ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest,'' and should therefore be approved and made effective
as mandatory Reliability Standards. NERC believes that, by following
NERC's Reliability Standards development process, a Reliability
Standard should meet the requirement that a standard be ``just,
reasonable, not unduly discriminatory or preferential.'' Further, NERC
asserts that, by filing with the Commission the written record of
development for each Reliability Standard, NERC has given the
Commission strong evidence that those 83 Reliability Standards are
just, reasonable, and not unduly discriminatory or preferential.
165. NERC states that the requirement that a Reliability Standard
be ``in the public interest'' provides the Commission with broad
discretion to review and approve a Reliability Standard. According to
NERC, implicit in the ``public interest'' test is that a Reliability
Standard is technically sound and ensures an adequate level of
reliability, and that the Reliability Standards provides a
comprehensive and complete set of technically sound requirements that
establish an acceptable threshold of performance necessary to ensure
reliability of the Bulk-Power System. NERC states that it believes that
approving those 83 Reliability Standards as enforceable as NERC begins
operating as the ERO meets this objective and will achieve an adequate
level of reliability as required by law. NERC asserts that adopting
fewer of the Reliability Standards would both create potential
reliability risks and communicate that some aspects of reliability are
not viewed as important enough to be the subject of mandatory and
enforceable Reliability Standards under the FPA.
166. FirstEnergy states that each proposed standard should be
reviewed against the following criteria: (1) Clarity; (2) technical
means to comply; (3) practicability; (4) consistency and (5) costs.
b. Commission Determination
167. The Commission agrees with NERC that an open and transparent
process is important in implementing section 215 of the FPA and
developing proposed mandatory Reliability Standards. However, in Order
No. 672, the Commission rejected the presumption that a proposed
Reliability Standard developed through an ANSI-certified process
automatically satisfies the statutory standard of review.\83\ The
Commission reiterates that simply because a proposed Reliability
Standard has been developed through an adequate process does not mean
that it is adequate as a substantive matter in protecting reliability.
We will, therefore, review each Reliability Standard to ensure that the
Reliability Standard is just, reasonable, not unduly discriminatory or
preferential, and in the public interest, giving due weight to the ERO.
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\83\ Order No. 672 at P 338.
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168. In response to FirstEnergy, the Commission has already laid
out the factors against which to review a Reliability Standard, as well
as other considerations.\84\ The Commission has no need to revisit this
issue.
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\84\ Id. at P 262, 321-37. (A proposed Reliability Standard
must: (1) Provide for the Reliable Operation of Bulk-Power System
facilities; (2) be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve this goal; (3)
be clear and unambiguous regarding what is required and who is
required to comply; (4) clearly state the possible consequences for
violating the proposed Reliability Standard; (5) include a clear
criterion or measure of whether an entity is in compliance with a
proposed Reliability Standard; (6) achieve its reliability goal
effectively and efficiently; (7) not reflect the ``lowest common
denominator.'')
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2. Commission Options When Acting on a Reliability Standard
169. In the NOPR, the Commission proposed that, for this
rulemaking, it would take one of four actions with regard to each
proposed Reliability Standard: (1) Approve; (2) approve as mandatory
and enforceable; and direct modification pursuant to section 215(d)(5);
(3) request additional information; or (4) remand. In fact, the NOPR
did not propose to remand any proposed Reliability Standard.\85\
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\85\ NOPR at P 78-82.
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170. With regard to the second category, the Commission explained
that it 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.
171. With regard to the third category, ``request additional
information,'' the NOPR explained that some Reliability Standards do
not contain sufficient information to enable the Commission to propose
a disposition. For those Reliability Standards, the Commission
identified the needed information, and proposed not to approve or
remand these Reliability Standards until all the relevant information
is received. As an example, the NOPR explained that many of the fill-
in-the-blank standards would not be approved or remanded until the
Commission had received all the necessary information.
a. Comments
172. Most commenters generally support the Commission's proposal to
have four courses of action it may take on a Reliability Standard.
However, Xcel has concerns about the legality of approving many of the
proposed Reliability Standards as mandatory but, at the same time,
ordering the ERO to make specific modifications to them. According to
Xcel, section 215(d) does not expressly create this ``approve but
modify'' option. To the contrary, section 215(d)(4) suggests that the
Commission should remand to the ERO a standard that it disapproves ``in
whole or in part.''
173. While many commenters support the Commission proposal to
approve certain Reliability Standards as mandatory and enforceable; and
direct NERC to modify them pursuant to section 215(d)(5), they are
concerned that the Commission's directives to modify certain
Reliability Standards are too prescriptive.\86\ They contend that, in
prescribing particular requirements, metrics, or specific language to
be used, the Commission is setting the Reliability Standard outside the
open Reliability Standards development process and not giving due
weight to the ERO under section 215 of the FPA. NRECA, for example,
argues there is a major distinction between (a) requiring a Reliability
Standard to address a specific matter and (b) requiring (as opposed to
suggesting) a specific Reliability Standard or requiring a reliability
matter to be addressed in a specific way. These commenters ask that the
Final Rule state that a directive to improve a Reliability Standards be
in the form of an objective to be achieved or concern or deficiency to
be resolved within the Reliability Standard, rather than a particular
requirement, metric, or specific language to be used.
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\86\ See, e.g., NERC, Entergy, EEI, APPA, National Grid, NRECA,
TAPS, ISO-NE and Duke.
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174. Many commenters request that the Commission require that
changes to any Reliability Standard be made through NERC's Reliability
Standard
[[Page 16436]]
development procedure.\87\ NERC states that there are areas where the
Commission proposes a specific directive on a particular Reliability
Standard that is well beyond the bounds of current utility practice.
According to NERC, these recommendations are often derived from the
Staff Preliminary Assessment or are based on a limited number of
comments to that assessment. NERC anticipates that the issue of concern
with respect to these Reliability Standards will be addressed, but the
results may be somewhat different than anticipated by the Commission.
Similarly, EEI and Progress state that NERC should not pre-determine
the outcome of the Reliability Standard development procedure in
response to the Commission's guidance. Ontario IESO states that the
Commission should allow its detailed input on the proposed Reliability
Standards to be considered through Reliability Standards development
process.
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\87\ See, e.g., NERC, EEI, ELCON, CEA, NYSRC, TVA, LPPC, NPCC,
Ontario IESO, Constellation, Progress and Dynegy.
---------------------------------------------------------------------------
175. According to EEI, NERC should be permitted to provide, if the
Commission's guidance for modification of a proposed Reliability
Standard is not adopted in the Reliability Standard development
procedure, an explanation for that outcome when it submits the modified
standard to the Commission for approval. Constellation asks the
Commission to clarify that, if the ERO Reliability Standards
development process does not result in a Reliability Standard that
includes the Commission's proposed modifications, the existing
Reliability Standard would remain in effect until such time as NERC
proposes and the Commission approves a different Reliability Standard
(approved through the Reliability Standards development process).
176. Manitoba and Northwest Requirements Utilities disagree with
the Commission's proposal to approve certain Reliability Standards and,
separately, direct NERC to make modifications. Some commenters, such as
California PUC, Northwest Requirements Utilities and SMA state that the
users, owners and operators of the Bulk-Power System should not be
expected to comply with Reliability Standards that are not finalized or
need modification. Northwest Requirements Utilities contends that
complete and clear Reliability Standards and requirements are necessary
to fair enforcement, particularly if monetary sanctions may apply.
Manitoba and California PUC state that approving Reliability Standards
that still require modification would lead to differing interpretations
of the Reliability Standards and confusion.
177. CEA asserts that the proposed directives to modify certain
Reliability Standards, while not remands, reflect engagement in the
standards-setting process that may interfere with the ERO's ability to
effectively function as an international body. For example, Manitoba
states that the Commission's proposed modifications without industry
input may unintentionally place Manitoba in a position where it must
recommend that the Government of Manitoba disallow the Commission's
prescribed modifications to several NERC Reliability Standards, thus
creating discrepancies between Reliability Standards across North
America.
178. FirstEnergy agrees with the Commission's rejection of the
concept of ``conditional approval'' in favor of approve but modify to
ensure that enforceable standards are in place. However, it asks that
the Commission consider waiving, or at least substantially reducing,
penalties for violations of some enforceable, but yet-to-be-completed
or modified Reliability Standards because compliance with such
Reliability Standards may prove difficult to determine. FirstEnergy
therefore suggests that the Commission exercise due discretion in
enforcing affected Reliability Standards, especially where the
Commission itself has found that a standard is incomplete or ambiguous.
International Transmission agrees that in instances where the
Commission has proposed material changes to a Reliability Standard and
its associated measurements, risk factors and Levels of Non-Compliance,
it may be appropriate for the ERO to exercise enforcement discretion on
a case-by-case basis.
179. SoCal Edison is concerned that entities may not have an
opportunity to (1) review the Reliability Standards that are adopted in
the Final Rule and (2) make any necessary changes in their operating or
planning practices in order to incorporate differences between the NOPR
and the Final Rule. SoCal Edison recommends the Commission specifically
state the ``effective date'' for compliance with each Reliability
Standard in its Final Rule. SoCal Edison is concerned because some
standards have a proposed NERC ``effective'' date after the Final Rule.
180. Northern Indiana states it is concerned how a June 2007
effective date will impact electric system reliability during the
critical summer peak demand period, particularly given the many
problems with the standards that have been identified. Northern Indiana
believes the Commission's current actions may, in the near term, create
a lower probability of success in achieving the Commission's stated
objectives. Northern Indiana suggests that the traditional summer peak
season is not a good time to implement broad changes in electric system
operations, procedures and protocols.
181. NRECA states it is concerned by the NOPR's efforts to
establish specific one and three year time frames for resolution of
various matters. It states that the Commission is authorized to comment
on priorities and suggest timing, it must allow NERC to follow its
ANSI-certified Reliability Standards development process.
182. NERC requests that the Commission provide a directive in the
Final Rule requiring NERC to address both the Commission's concerns
with the existing Reliability Standards and all comments filed in this
rulemaking proceeding suggesting specific improvements to the
Reliability Standards. NERC states that if the Commission acts on the
views expressed on a specific Reliability Standard by an individual
commenter in this rulemaking, it may encourage others to avoid
participating in the NERC process and instead wait until a proposed new
or modified Reliability Standard reaches the Commission approval stage
to express their views on the standards. NERC states that no commenter
should be entitled to have its comments on a specific Reliability
Standard resolved by the Commission in this rulemaking proceeding.
183. NERC maintains that referring all comments to the NERC
Reliability Standards development process for resolution is consistent
with NERC's obligation to facilitate an open stakeholder process for
the development of Reliability Standards. NERC asserts that it gives
fair consideration to all comments and objections on a proposed new or
revised Reliability Standard and such comments are either resolved to
the satisfaction of the commenter, or reasons are stated as to why the
commenter's recommendation should not be adopted.
b. Commission Determination
184. The Commission affirms the four possible courses of action
that it will take with regard to each proposed Reliability Standard:
(1) Approve; (2) approve as mandatory and enforceable; and direct
modification pursuant to section 215(d)(5); (3) request additional
information; or (4) remand. Each course of action is justified and has
a sound basis in the statute. Xcel questions the
[[Page 16437]]
legality of the second option above, which it incorrectly equates to
``conditional acceptance.'' Rather, as explained in the NOPR,\88\ the
Commission is taking two independent actions, both authorized by the
statute. First, we are exercising our authority, contained in section
215(d)(2) of the FPA, to approve a proposed Reliability Standard.
Second, we are directing the ERO 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.\89\
Accordingly, we reject Xcel's contention and adopt the NOPR proposal on
this matter.
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\88\ See NOPR at P 79-80.
\89\ 16 U.S.C. 824o(d)(5) ( ``[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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185. With regard to the many commenters that raise concerns about
the prescriptive nature of the Commission's proposed modifications, the
Commission agrees that a direction for modification should not be so
overly prescriptive as to preclude the consideration of viable
alternatives in the ERO's Reliability Standards development process.
However, in identifying a specific matter to be addressed in a
modification to a Reliability Standard, it is important that the
Commission provide sufficient guidance so that the ERO has an
understanding of the Commission's concerns and an appropriate, but not
necessarily exclusive, outcome to address those concerns. Without such
direction and guidance, a Commission proposal to modify a Reliability
Standard might be so vague that the ERO would not know how to
adequately respond.
186. Thus, in some instances, while we provide specific details
regarding the Commission's expectations, we intend by doing so to
provide useful guidance to assist in the Reliability Standards
development process, not to impede it.\90\ We find that this is
consistent with statutory language that authorizes the Commission to
order the ERO to submit a modification ``that addresses a specific
matter'' if the Commission considers it appropriate to carry out
section 215 of the FPA.\91\ In the Final Rule, we have considered
commenters' concerns and, where a directive for modification appears to
be determinative of the outcome, the Commission provides flexibility by
directing the ERO to address the underlying issue through the
Reliability Standards development process without mandating a specific
change to the Reliability Standard. Further, the Commission clarifies
that, where the Final Rule identifies a concern and offers a specific
approach to address the concern, we will consider an equivalent
alternative approach provided that the ERO demonstrates that the
alternative will address the Commission's underlying concern or goal as
efficiently and effectively as the Commission's proposal.
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\90\ Moreover, in the NOPR, the Commission first discussed in
detail its substantive concerns regarding a particular proposed
Reliability Standard and, to provide greater clarity regarding the
Commission proposal, then summarized the proposed findings and
modifications. It appears that such summaries of broader and fuller
discussions led to misunderstandings of the NOPR proposals.
\91\ 16 U.S.C. 824o(d)(5).
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187. Consistent with section 215 of the FPA and our regulations,
any modification to a Reliability Standard, including a modification
that addresses a Commission directive, must be developed and fully
vetted through NERC's Reliability Standard development process. The
Commission's directives are not intended to usurp or supplant the
Reliability Standard development procedure. Further, this allows the
ERO to take into consideration the international nature of Reliability
Standards and incorporate any modifications requested by our
counterparts in Canada and Mexico. Until the Commission approves NERC's
proposed modification to a Reliability Standard, the preexisting
Reliability Standard will remain in effect.
188. We agree with NERC's suggestion that the Commission should
direct NERC to address NOPR comments suggesting specific new
improvements to the Reliability Standards, and we do so here. We
believe that this approach will allow for a full vetting of new
suggestions raised by commenters for the first time in the comments on
the NOPR and will encourage interested entities to participate in the
ERO Reliability Standards development process and not wait to express
their views until a proposed new or modified Reliability Standard is
filed with the Commission. As noted throughout the standard-by-standard
analysis that follows, various commenters provide specific suggestions
to improve or otherwise modify a Reliability Standard that address
issues not raised in the NOPR. In such circumstances, the Commission
directs the ERO to consider such comments as it modifies the
Reliability Standards during the three-year review cycle contemplated
by NERC's Work Plan through the ERO Reliability Standards development
process. The Commission, however, does not direct any outcome other
than that the comments receive consideration.
189. We disagree with commenters, such as Xcel, suggesting that the
Commission should not approve Reliability Standards that we require
NERC to modify. The Commission is only approving those Reliability
Standards that it has determined to be just, reasonable, not unduly
discriminatory or preferential, and in the public interest. As
discussed more fully in the discussion of the individual Reliability
Standards, we have determined that each approved Reliability Standard
is sufficiently clear and independently enforceable. Because we believe
that these Reliability Standards are enforceable as written, the
Commission will not exempt them from enforcement.
190. The Commission disagrees with Northern Indiana that the
Reliability Standards should not be implemented in summer of 2007.\92\
Most or all users, owners and operators of the Bulk-Power System have
participated in NERC's voluntary reliability regime for years and are
familiar with the proposed Reliability Standards. Others have had
notice of the Reliability Standards since they were filed by NERC in
April 2006. We are not persuaded that making Reliability Standards
enforceable, most of which were being complied with on a voluntary
basis, will require broad changes in electric system operations,
procedures and protocols. Therefore, we do not see any reason to
further delay implementation of the mandatory Reliability Standards.
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\92\ See discussion below regarding the Trial Period, section
II.D.4.
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191. In response to SoCal Edison, Reliability Standards will become
effective the latter of the effective date of this Final Rule or the
ERO's proposed NERC effective date. The Commission disagrees with SoCal
Edison that users, owners and operators of the Bulk-Power System will
not have an opportunity to review the Reliability Standards that are
adopted in the Final Rule and incorporate differences between the NOPR
and the Final Rule into their operating practices. The Reliability
Standards approved in this Final Rule are approved as proposed by the
ERO. No changes will be made immediately based on the Commission's
direction to modify those Reliability Standards. Any modifications will
be developed through the ERO's Reliability Standards development
process and should have a
[[Page 16438]]
proposed effective date that will take into account any time needed for
users, owners and operators of the Bulk-Power System to incorporate the
necessary changes. Therefore, there is no need for any entity to make
any changes based on differences between the NOPR and the Final Rule.
192. NRECA's assertion that the Commission should not establish
timelines to resolve matters is a collateral attack on Order No. 672.
In that order, the Commission adopted its regulations to provide that
the Commission, when ordering the ERO to submit to the Commission a
proposed Reliability Standard or proposed modification to a Reliability
Standard that addresses a specific matter, may order a deadline by
which the ERO must submit a proposed or modified Reliability
Standard.\93\
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\93\ See 18 CFR 39.5(g).
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3. Prioritizing Modifications to Reliability Standards
193. As discussed above, the Commission proposed to approve certain
Reliability Standards and, as a separate action, proposed to direct the
ERO to modify many of the same Reliability Standards pursuant to
section 215(d)(5) of the FPA. In the NOPR, the Commission recognized
that it is not reasonable to expect the modification of such a
substantial number of Reliability Standards in a short period of time.
Thus, the NOPR provided guidance on the prioritization of needed
modifications.\94\
---------------------------------------------------------------------------
\94\ NOPR at P 85-87.
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194. The NOPR proposed that NERC first focus its resources on
modifying those Reliability Standards that have the largest impact on
near-term Bulk-Power System reliability, including many of the proposed
modifications that reflect Blackout Report recommendations. Further,
the Commission identified a group of Reliability Standards that it
believes should be given the highest priority by the ERO based on the
above guidance.\95\ The NOPR explained that the list is not meant to be
exclusive or inflexible and solicited ERO and commenter input. The NOPR
proposed that NERC address the ``high priority'' modifications within
one year of the effective date of the Final Rule.
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\95\ Id. at Appendix D (High Priority List).
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195. In addition, the NOPR proposed that the ERO promptly address
certain proposed modifications that are not necessarily identified as
``high priority'' but may be addressed in a relatively short time frame
because the proposed modifications are relatively minor or
``administrative'' in nature. The NOPR further proposed 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
would take a staggered approach and complete all the proposed
modifications within either two or three years from the effective date
of the Final Rule.
196. As noted above, on December 1, 2006, NERC submitted its Work
Plan as an informational filing. According to the Work Plan, NERC will
revise the existing Reliability Standards to incorporate improvements.
A total of 31 different projects will be completed over a three-year
period.\96\ Some of the projects address revising a single Reliability
Standard. The largest project includes revising 19 Reliability
Standards focusing on related topics. NERC asserts that grouping the
Reliability Standards in this manner will be the most efficient use of
the resources and will allow consistency in requirements on related
standards. NERC states that the Work Plan incorporates modifications
that were proposed in the NOPR, but it will modify its Work Plan to
align it with the modifications the Commission orders in the Final
Rule. In addition, the Work Plan will remain dynamic as new Reliability
Standards are proposed and priorities evolve. The Work Plan will be
updated on an annual basis, and more frequently if needed.
---------------------------------------------------------------------------
\96\ Some projects relate to new Reliability Standards that are
not before the Commission in the instant rulemaking.
---------------------------------------------------------------------------
197. According to the Work Plan, NERC will periodically report
progress and revisions to the Work Plan and timetable to the
Commission. NERC's intent is to provide accountability for the revision
and development of Reliability Standards, while recognizing it is
impossible to have a fixed schedule when working in a consensus-driven
process addressing complex technical matters.
a. Comments
198. NERC states that it is pleased that the Commission did not
propose specific deadlines in the NOPR for completing the directives to
improve the Reliability Standards. NERC requests that the Commission
not state specific delivery dates, because developing consensus
Reliability Standards on complex technical matters within fixed time
frames may not be realistic in all cases. NERC states that it will
report the reasons for any delays in the schedule and will work to
ensure that no unnecessary delays occur due to lack of attention or
effort.
199. NERC expresses concern that the Commission suggests in the
NOPR that it may direct some early modifications to the Reliability
Standards that appear to provide quick results.\97\ According to NERC,
because of the procedural requirements of the Reliability Standards
development process, this would delay work that is more important. NERC
states that it can make such changes quickly for a particular
Reliability Standard if there are no other changes to that standard.
However, NERC's Work Plan contemplates that almost every Reliability
Standard is to be upgraded; modifying each standard in multiple steps
would add significant delay.
---------------------------------------------------------------------------
\97\ NOPR at P 86.
---------------------------------------------------------------------------
200. APPA similarly cautions the Commission that the industry does
not have unlimited ability to simultaneously reevaluate the Reliability
Standards, prepare for NERC's and the Regional Entities' compliance
monitoring and enforcement programs, and actually plan and operate
their utility systems on a reliable basis. According to APPA, NERC
should promptly address the administrative elements of those
Reliability Standards that are now at best incomplete, with missing
Compliance Measures, Levels of Non-Compliance and Violation Risk
Factors. NERC must also deal with the regional fill-in-the-blank
standards and criteria that have not yet been submitted to either NERC
or to the Commission for review and approval.
201. International Transmission states that the Commission should
not direct NERC to make changes to the Reliability Standards within a
specific time frame because this would circumvent the Reliability
Standard development process. It asks the Commission to instruct the
ERO to initiate the Reliability Standards development process in a time
frame that would likely result in their presentation to the Commission
by a desired date, acknowledging that a revised Reliability Standard
may not reach industry consensus and thus not meet the Commission's
desired time frame. Further, International Transmission believes that
the priority of a Reliability Standard for subsequent modification
should be based on the standard's ``Violation Risk Factor.''
Reliability Standards that have the greatest impact on bulk electric
system reliability should be addressed first. All high risk
requirements should be addressed in the 2007 Work Plan. International
Transmission states the addition of Measures and Levels of Non-
[[Page 16439]]
Compliance is neither minor nor administrative in nature, although
designated by the Commission as such and called for an accelerated time
period for their addition.
202. MRO recommends that the Commission place a greater emphasis on
directing NERC to develop clear and measurable Requirements. If the
Requirements are not clear and measurable, the Measures and Levels of
Non-Compliance will be fundamentally flawed. MRO also states that there
are numerous Requirements that are now part of the Reliability
Standards that came from elements of the former NERC Operating Manual
that were never intended as Requirements. It believes that this, in
part, has created certain difficulties that have resulted in a lack of
Measures or Levels of Non-Compliance in the Reliability Standards. MRO
provides examples of such difficulties in its comments regarding
specific Reliability Standards. MRO suggests grouping each Requirement
with its associated Measure and Level of Non-Compliance thus making it
clear to the user, owner or operator as to which Requirements, Measures
and Levels of Non-Compliance are related thereby reducing confusion.
203. APPA and Alcoa state that the Commission did not give
sufficient time for comments on NERC's submitted Work Plan. APPA notes
that the Work Plan will have to be revised following issuance of the
Final Rule.
b. Commission Determination
204. Given the concerns raised by commenters, the Commission will
not adopt the NOPR's proposal to direct some early modifications to the
Reliability Standards. We agree with NERC that modifying each
Reliability Standard first to address administrative concerns, then
sending it back to the Reliability Standards development process to
address any modifications directed by the Commission or requested by
stakeholders, might lead to an unacceptable delay.
205. While the Commission agrees with International Transmission
that a good starting point for prioritizing modifications to a
Reliability Standard could be based on the Reliability Standard's
``Violation Risk Factor,'' the Commission will not mandate that the ERO
do so. The ERO should take into account the views of its stakeholders,
including the concerns raised in this proceeding by APPA, International
Transmission and MRO, in revising its Work Plan following issuance of
this Final Rule.
206. In Order No. 890, the Commission directed public utilities,
working through NERC, to modify the ATC-related Reliability Standards
within 270 days of publication of Order No. 890 in the Federal
Register.\98\ Our action there affects approximately nine MOD
Reliability Standards and one FAC Reliability Standard that are before
us in this proceeding. The ERO must submit its revised Work Plan within
90 days of the effective date of the Reliability Standards approved in
this order as an informational filing to: (1) Reflect modification
directives contained in the Final Rule; (2) include the timeline for
completion of ATC-related Reliability Standards as ordered in Order No.
890 and (3) account for the views of its stakeholders, including those
raised in this proceeding.
---------------------------------------------------------------------------
\98\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266(March 15, 2007),
FERC Stats. & Regs. ] 31,241 (2007) at P 223.
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207. The Commission disagrees with NERC that we should not set
specific delivery dates. A Work Plan with specific target dates will
provide a valuable tool and incentive to timely address the
modifications directed in this Final Rule. We note that the ERO
previously prepared and submitted to the Commission for informational
purposes one iteration of such a Work Plan that identifies target dates
for the modification of Reliability Standards. Accordingly, we direct
the ERO to submit as an informational filing, within 90 days of the
effective date of this Final Rule, a Work Plan that identifies a plan
for addressing the modifications to the Reliability Standards directed
by the Commission in this Final Rule and a schedule with delivery dates
for completing such modifications. The ERO should make every effort to
meet such delivery dates. However, we understand that there may be
certain cases in which the ERO is not able to meet a Commission's
deadline. In those instances, the ERO must inform the Commission of its
inability to meet the specified delivery date and explain why it will
not meet the deadline and when it expects to complete its work.
4. Trial Period
208. NERC and some commenters to the Staff Preliminary Assessment
recommended that the Commission establish a ``trial period'' during
which time the ERO would determine, but not collect, monetary
penalties. In the NOPR, the Commission expressed concern that a trial
period that commences with the effective date of mandatory and
enforceable Reliability Standards may interfere with their being made
effective by summer 2007. Thus, the NOPR did not propose a trial
period.\99\
---------------------------------------------------------------------------
\99\ Id. at P 92-93.
---------------------------------------------------------------------------
209. However, the Commission recognized that there are entities
that have not historically participated in the pre-existing voluntary
reliability system (including some relatively small entities) that may
not be familiar with what is required for compliance with the proposed
mandatory Reliability Standards. For such entities, the NOPR proposed
that the ERO and Regional Entities use their 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.
a. Comments
210. Most commenters request that the Commission reconsider the
proposal to reject a trial period during which the Reliability
Standards are mandatory and enforceable but during which penalties
would not be assessed for violating a Reliability Standard.\100\ EEI,
for example, notes that the compliance enforcement program and the
delegation agreements have not yet been approved by the Commission and
there may be a short time between their approval and the projected
start date for enforcing the Reliability Standards. Therefore,
commenters generally state that a trial period is appropriate to ensure
that the compliance monitoring and enforcement processes work as
intended and that entities have time to implement new processes, such
as required data systems; after June 2007, commenters generally state
that NERC and the Regional Entities would be able to require remedial
actions where there is an immediate actual or potential risk to
reliable interconnected operations. Further, some state that a trial
period would allow NERC to resolve issues with unfinished standards or
ambiguous standards for which the Commission has directed improvements.
If the Commission rejects a six-month trial period, several entities,
such as EEI, PG&E, Xcel and NYSRC, request that the Commission extend
NERC's discretionary enforcement to all entities, not just those new to
the Reliability Standards.
---------------------------------------------------------------------------
\100\ See, e.g., EEI, APPA, TAPS, EPSA, CAISO, Bonneville,
California PUC, Cleveland, Otter Tail, Northwest Requirements
Utilities, TVA and SMA.
---------------------------------------------------------------------------
211. NPCC essentially agrees with the Commission that there should
be no trial period, but if the definition of Bulk-Power System is
substantially altered to
[[Page 16440]]
draw in a broad range of entities that have not traditionally been
subject to pre-existing reliability standards, a transition period is
appropriate to bring them into compliance. Where a Reliability Standard
has missing or incomplete compliance measures, ATC states that the
Commission should make these standards mandatory to avoid gaps, but not
assess monetary penalties for non-compliance. ATC agrees with the
Commission that the new mandatory reliability regime should be
operational by June 2007, noting that it has been over three years
since the August 2003 Blackout and over a year since EPAct 2005 was
enacted.
212. Several entities state that the Commission's proposal to allow
the ERO and Regional Entities discretion in setting penalties does not
go far enough, even if it is applied to all users, owners and operators
of the Bulk-Power System. For example, SERC maintains that its proposed
delegation agreement and the NERC Compliance Monitoring and Enforcement
Program may not allow discretion in imposing penalties.
213. NERC states that it understands and supports the importance
the Commission places on the ERO having the ability to impose a
financial penalty if a Bulk-Power System user, owner or operator
violates a mandatory Reliability Standard that is in effect, especially
for egregious behavior. However, NERC continues to maintain that a
validation period for the compliance process and the calculation of
penalties is important and proposes a modified approach to that taken
by the Commission. NERC asks the Commission to authorize NERC and the
Regional Entities to exercise discretion to calculate financial
penalties, but not collect them in the case of most violations through
December 31, 2007. At the same time it asks the Commission to specify
that in a situation in which an entity violates a clear and well-
understood Reliability Standard that causes a significant disturbance
on the Bulk-Power System, or in the face of other aggravating
circumstances such as repeated or intentional violations, the ERO and
the Regional Entities would have the authority and responsibility to
hold the offending entity fully accountable for the violation, by the
assessment of financial penalties.
214. NERC states that this alternative approach is supported by the
newness of the compliance enforcement program, the Sanctions Guidelines
and the penalty matrix, and the Violation Risk Factors, which have not
been approved by the Commission. Further, NERC claims that initiating
operations under mandatory Reliability Standards with the collection of
penalties as the rule rather than the exception may increase the risk
of numerous legal challenges occurring in the early stages of
implementing mandatory Reliability Standards, whereas NERC would expect
a rapid decline in such challenges after its proposed validation
period. In a reply comment, Xcel supports NERC's proposed approach.
215. If the Commission rejects NERC's proposed modified approach,
NERC asks that it and the Regional Entities be given broad discretion
in setting penalties during this time period and that this discretion
not be limited to small entities or those who are new to Reliability
Standards. Avista/Puget also urges the Commission, the ERO and the
Regional Entities to exercise enforcement discretion more broadly than
proposed in the NOPR. Penalties should be waived for an initial period
in several situations, including where a Reliability Standard is
applied based on new or different interpretations.
216. Some commenters request that the Commission grant a longer
trial period in certain cases. For instance, TANC believes that for
smaller entities the Commission should, at a minimum, adopt a trial
period of at least one year to provide adequate time to evaluate and
comply with the new mandatory Reliability Standards. Bonneville and
NPCC suggest that, for Reliability Standards that have an annual
reporting requirement, the compliance cycle should start on June 2007
so that a Reliability Standard that relies on data reporting back into
the prior year should have an initial compliance measurement date of
June 2008. AMP-Ohio states that the Commission's proposal does not go
far enough and suggests a ``ramp-up'' period for entities that are new
to standards, through and including the entity's first compliance audit
or, if the Commission rejects this proposal, the Commission should
extend the trial period from six to twelve months. Reliant also
advocates a phase-in of penalties over six to twelve months, with an
increasing scale of penalties over time.
217. Portland General and Tacoma request that the Commission
institute a one-year trial period to allow the industry time to
finalize the language of the mandatory Reliability Standards and to
allow users, owners and operators time to adapt to the final language.
For any Reliability Standard that requires modification, Tacoma
requests that the Commission provide a six-month trial period beyond
the date when the Reliability Standard is completed. Bonneville asks
that the Commission extend the trial period for Reliability Standards
that have missing or ambiguous measures or severity levels until those
issues are resolved. National Grid states that enforcement discretion
should not be limited in scope or duration and should be extended to
any situation in which a Reliability Standard is applied in a novel
manner, including when a Reliability Standard is interpreted for the
first time.
218. PG&E asserts that NERC and the Regional Entities should have
discretion in imposing fines for violations of Reliability Standards
during a transition period. Where an entity shows a good faith effort
to comply with a new or changed Reliability Standard promptly and
thoroughly, NERC and/or the Regional Entity should be permitted to
consider those efforts in assessing fines. PG&E suggests a transition
period of three to six months. Without such discretion, entities may be
pressured to implement Reliability Standards hastily and inadequately.
PG&E also notes that some entities in WECC have voluntarily
participated in WECC's enforcement program. The new regime entails
procedural and substantive changes. Entities that have complied
voluntarily should not be penalized by denying them an opportunity to
adjust.
219. WECC states that it continues to believe that a trial period
of more than six months is appropriate, but it is not requesting that
the Commission revisit its decision on this issue. WECC asks that
Regional Entities have somewhat greater flexibility in monitoring and
enforcing compliance during the initial period of implementation.
According to WECC, the Commission should recognize that, in the early
stages of implementation, penalties should be reserved for clear
situations where Registered Entities are refusing to comply.
Unreasonably harsh enforcement in the early stages of implementation
may damage the current level of reliability by diverting resources away
from developing solutions in order to avoid fines and support
litigation. This flexibility should continue beyond six months after
the effective date, if necessary, for those Reliability Standards
requiring modification, until such modifications have become effective.
220. According to WECC, it is extremely important that United
States, Canadian and Mexican authorities enforce their respective
standards within WECC in a way that avoids conflicting obligations.
WECC thus suggests that the Commission grant WECC substantial
discretion to focus on education and facilitation of compliance with
NERC Reliability Standards while
[[Page 16441]]
it seeks to promote consistent enforcement internationally.
b. Commission Determination
221. The Commission adopts its proposal not to institute a formal
trial period. As we explained in the NOPR, a trial period is
inconsistent with mandatory and enforceable Reliability Standards
taking effect in a timely manner.\101\ The Commission's overriding
concern is the reliability of the Bulk-Power System, and mandatory and
enforceable Reliability Standards becoming effective in a timely manner
are essential to ensuring the reliability of the Bulk-Power System.
Accordingly, the Commission will not adopt a formal trial period.
---------------------------------------------------------------------------
\101\ NOPR at P 92.
---------------------------------------------------------------------------
222. The Commission is, however, also cognizant of commenters'
concerns. In the NOPR, the Commission proposed that the ERO and
Regional Entities use their enforcement discretion in imposing
penalties on entities that historically had not participated in the
pre-existing voluntary reliability regime, although authority to impose
a penalty on such an entity would be retained ``if warranted by the
circumstances.'' \102\ In light of commenters'' concerns, including the
fact that there are new aspects to the Reliability Standards and the
proposed compliance program that will apply to all users, owners and
operators of the Bulk-Power System, the Commission directs the ERO and
Regional Entities to focus their resources on the most serious
violations during an initial period through December 31, 2007. This
thoughtful use of enforcement discretion should apply to all users,
owners and operators of the Bulk-Power System, and not just those new
to the program as originally proposed in the NOPR. This approach will
allow the ERO, Regional Entities and other entities time to ensure that
the compliance monitoring and enforcement processes work as intended
and that all entities have time to implement new processes.
---------------------------------------------------------------------------
\102\ Id. at P 93.
---------------------------------------------------------------------------
223. By directing the ERO and Regional Entities to focus their
resources on the most serious violations through the end of 2007, the
ERO and Regional Entities will have the discretion necessary to assess
penalties for such violations, while also having discretion to
calculate a penalty without collecting the penalty if circumstances
warrant. Further, even if the ERO or a Regional Entity declines to
assess a monetary penalty during the initial period, they are
authorized to require remedial actions where a Reliability Standard has
been violated. Furthermore, where the ERO uses its discretion and does
not assess a penalty for a Reliability Standard violation, we encourage
the ERO to establish a process to inform the user, owner or operator of
the Bulk-Power System of the violation and the potential penalty that
could have been assessed to such entity and how that penalty was
calculated. We leave to the ERO's discretion the parameters of the
notification process and the amount of resources to dedicate to this
effort. Moreover, the Commission retains its power under section
215(e)(3) of the FPA to bring an enforcement action against a user,
owner or operator of the Bulk-Power System.
224. The Commission believes that the goal should be to ensure
that, at the outset, the ERO and Regional Entities can assess a
monetary penalty in a situation where, for example, an entity's non-
compliance puts Bulk-Power System reliability at risk. Requiring the
ERO and Regional Entities to focus on the most serious violations will
allow the industry time to adapt to the new regime while also
protecting Bulk-Power System reliability by allowing the ERO or a
Regional Entity to take an enforcement action against an entity whose
violation causes a significant disturbance. Our approach strikes a
reasonable balance in ensuring that the ERO and Regional Entities will
be able to enforce mandatory Reliability Standards in a timely manner,
while still allowing users, owners and operators of the Bulk-Power
System time to acquaint themselves with the new requirements and
enforcement program. In addition, our approach ensures that all users,
owners and operators of the Bulk-Power System take seriously mandatory,
enforceable reliability standards at the earliest opportunity and
before the 2007 summer peak season.
225. National Grid, among others, states that the Commission should
allow enforcement discretion on an ongoing basis, for example, when the
ERO or a Regional Entity interprets a Reliability Standard for the
first time. The Commission agrees that, separate from our specific
directive that all concerned focus their resources on the most serious
violations during an initial period, the ERO and Regional Entities
retain enforcement discretion as would any enforcement entity. Such
discretion, in fact, already exists in the guidelines; as we stated in
the ERO Certification Order, the Sanction Guidelines provide
flexibility as to establishing the appropriate penalty within the range
of applicable penalties.\103\
---------------------------------------------------------------------------
\103\ ERO Certification Order at P 451.
---------------------------------------------------------------------------
5. International Coordination
226. In response to concerns regarding international coordination
of action on proposed Reliability Standards, the Commission reaffirmed
its recognition of the importance of international coordination,
previously discussed in both Order No. 672 \104\ and the ERO
Certification Order.\105\
---------------------------------------------------------------------------
\104\ See Order No. 672 at P 400.
\105\ ERO Certification Order at P 286.
---------------------------------------------------------------------------
a. Comments
227. Ontario IESO agrees with the Commission ``that NERC's
development of a coordination process, together with the existing means
of communications and coordination such as the United States--Canada
Bilateral Electric Oversight Group will provide the necessary
mechanisms for international coordination'' and supports the
coordination process proposed by NERC in its October 18, 2006 filing in
Docket No. RR06-1-003.\106\
---------------------------------------------------------------------------
\106\ Compliance Filing of the North American Electric
Reliability Council and the North American Electric Reliability
Corporation Addressing Non-Governance Issues, Appendix 3C, Docket
No. RR06-1-000 (October 18, 2006).
---------------------------------------------------------------------------
228. EEI and National Grid state that it is not sufficient to
coordinate remands through NERC alone because both the Commission and
Canadian provincial authorities have the ultimate say in approving
applicable Reliability Standards. They advocate that the various
regulators commit to coordinate through a formal mechanism, such as a
memorandum of understanding. According to EEI, the Commission should
coordinate with its international counterparts when directing
modifications to Reliability Standards to ensure that the resulting
Reliability Standards are uniform to the greatest extent possible. NPCC
adds that the Commission should coordinate with its international
counterparts when proposing to hold, remand or reject a proposed
Reliability Standard to avoid inconsistencies in Reliability Standards
application.
229. National Grid states that, where similar interpretations and
modifications to Reliability Standards are not adopted by the
provincial authorities in Canada, there is potential for conflicting
requirements for interconnected facilities. The Alberta ESO is also
concerned that, due to regulatory/legislative requirements and industry
structures in Canada, some of the Reliability Standards may not be
implemented as they are written.
[[Page 16442]]
Therefore it requests that the Commission require that the
international coordination process include a provision where variances
are identified by these international governmental authorities to
minimize the possibility of a governmental authority remanding a
Reliability Standard. According to Alberta ESO, while the goal should
be consistent, North America-wide Reliability Standards, there will be
instances where this is not achievable.
230. WIRAB advises that some Canadian provinces or Mexican
authorities may approve NERC-proposed Reliability Standards with
changes or modifications. It is important to allow minor variations
across such jurisdictions to minimize the possibility of a governmental
authority remanding a Reliability Standard. According to WIRAB, the
goal should be a consistent system throughout North America with enough
flexibility for some jurisdictional variation when uniformity is not
immediately possible.
b. Commission Determination
231. In the January 2007 Compliance Order, the Commission stated
that, to minimize the possibility of a governmental authority directing
a remand, it seemed appropriate for such governmental authorities to
have an opportunity to provide NERC with input prior to its filing for
governmental approval of a proposed Reliability Standard.\107\ In that
order, the Commission agreed with NERC's proposal to facilitate
informal conferences to provide an opportunity for governmental
authorities to consult with NERC and stakeholder representatives
regarding Reliability Standard development work-plans, objectives and
priorities, and emerging Reliability Standards.\108\ While we did not
initiate a formal mechanism for coordination as EEI and National Grid
now suggest, we did state that we anticipate that the Commission and
counterpart governmental authorities in Canada and Mexico will convene
regular meetings to coordinate on issues relating to reliability. We
reaffirm that approach as an appropriate framework for addressing
matters of international coordination in the context of continent-wide
Reliability Standards.
---------------------------------------------------------------------------
\107\ January 2007 Compliance Order at P 44.
\108\ Id.
---------------------------------------------------------------------------
232. We agree with Alberta ESO and WIRAB that the goal should be
consistent, North America-wide Reliability Standards, but that this may
not be achievable in all instances. For example, in this rulemaking the
Commission is approving several regional differences in Reliability
Standards; in the United States, NERC identifies regional variations by
submitting them to the Commission in the form of a Reliability
Standard.\109\
---------------------------------------------------------------------------
\109\ Order No. 672 at P 296.
---------------------------------------------------------------------------
233. In response to WIRAB, if a governmental authority in Canada or
Mexico requests that NERC modify a continent-wide Reliability Standard
rather than create a regional variance, NERC must submit any revised
Reliability Standard to the Commission. The Commission will then have
an opportunity to review the proposed revised Reliability Standard,
taking into account the request of the foreign governmental authority.
E. Common Issues Pertaining to Reliability Standards
1. Blackout Report Recommendation on Liability Limitations
234. In the NOPR, the Commission stated that the Blackout Report
recommendations, many of which address key issues for assuring Bulk-
Power System reliability, have received international support and
represent a well-reasoned and sound basis for action. Thus, in the
discussion of a particular proposed Reliability Standard, the NOPR
often recognized the merit of a specific Blackout Report recommendation
and reaffirmed the reasoning behind such recommendation in proposing to
approve, with a proposed directive to modify, a specific Reliability
Standard. Further, the Commission indicated that a modification to a
proposed Reliability Standard based on a Blackout Report recommendation
should receive the highest priority in terms of NERC's Work Plan.\110\
---------------------------------------------------------------------------
\110\ NOPR at P 99-100.
---------------------------------------------------------------------------
235. The Blackout Report's Recommendation No. 8 recognized that
timely and sufficient action to shed load on August 14, 2003, would
have prevented the spread of the blackout beyond northern Ohio, and
recommended that legislative bodies and regulators should: (1)
Establish that operators (whether organizations or individuals) who
initiate load shedding pursuant to operational guidelines are not
subject to liability suits and (2) affirm publicly that actions to shed
load pursuant to such guidelines are not indicative of operator
failure.\111\
---------------------------------------------------------------------------
\111\ Blackout Report at 147
---------------------------------------------------------------------------
a. Comments
236. EEI states that the Commission should adopt OATT liability
limitations to implement Blackout Report Recommendation No. 8 because
compliance with mandatory Reliability Standards may expose transmission
operators to liability for actions required by a Reliability Standard;
Blackout Report Recommendation No. 8 identified this concern and
recommended that legislative bodies and regulators establish that
operators who initiate load shedding are not subject to liability. EEI
disagrees with the suggestion that the Commission cannot shield
operators from liability suits. EEI states that the Commission has the
authority under FPA sections 205 and 206 to provide liability
protection and has done so for several transmission operators in
several cases by approving amendments to open access transmission
tariffs providing for liability limitations.\112\ However, it notes
that the Commission has rejected efforts by other parties to implement
similar protections.\113\
---------------------------------------------------------------------------
\112\ EEI at 16, citing Southwest Power Pool, Inc., 112 FERC ]
61,100 (2005); Midwest Independent Transmission System Operator,
Inc., 110 FERC ] 61,164 (2005); ISO New England, Inc., 106 FERC ]
61, 280, order on reh'g, 109 FERC ] 61,147 (2004).
\113\ Id., citing Southern Company Services, Inc., 113 FERC ]
61,239 (2005).
---------------------------------------------------------------------------
b. Commission Determination
237. Consistent with Order No. 890, the Commission does not adopt
new liability protections.\114\ The Commission does not believe any
further action is needed to implement Blackout Report Recommendation
No. 8. First, the Task Force found that no further action is
needed.\115\ Further, the Blackout report indicated that some states
already have appropriate protection against liability suits.\116\
Finally, in Order No. 888, the Commission declined to adopt a uniform
federal liability standard and decided that, while it was appropriate
to protect the transmission provider through force majeure and
indemnification provisions from damages or liability when service is
provided by the transmission provider without negligence, it would
leave the determination of liability in other instances to other
proceedings.\117\ Order
[[Page 16443]]
No. 890 reaffirmed this decision. EEI has offered no arguments that
demonstrate that an OATT limit on liability is warranted.
---------------------------------------------------------------------------
\114\ Order No. 890 at P 1671-77.
\115\ U.S.-Canada Power System Outage Task Force, Final Report
on Implementation of Task Force Recommendations at 22 (Oct. 3,
2006), available at http://www.oe.energy.gov/news/blackout.htm
(``Action Required at Fully Implement Recommendation 8: No further
action under this recommendation is needed'').
\116\ Id. (``In the United States, some state regualtors have
informally expressed the view that there is appropriate protection
against liability suits for parties who shed load according to
approved guidelines.'')
\117\ Order No. 888-B, 81 FERC ] 61,248 at 62,081 (1997), order
on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in
relevant part sub nom. Transmission Access Policy Study Group v.
FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v.
FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------
2. Measures and Levels of Non-Compliance
238. The NOPR noted that, according to the Staff Preliminary
Assessment, a number of proposed Reliability Standards do not contain
Measures \118\ or Levels of Non-Compliance,\119\ or both. NERC, in its
petition, identified 21 Reliability Standards that lack Measures or
Levels of Non-Compliance and indicated that it planned to file modified
Reliability Standards that include the missing Measures and Levels of
Non-Compliance in November 2006. On November 15, 2006, NERC made this
filing.
---------------------------------------------------------------------------
\118\ 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 to the Staff Preliminary Assessment at 104.
\119\ ``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.
---------------------------------------------------------------------------
239. In the NOPR, while the Commission recognized the importance of
having Measures and Levels of Non-Compliance specified for each
Reliability Standard, the Commission also stated that the absence of
these two elements is not critical to the determination of whether to
approve a proposed Reliability Standard. Rather, the most critical
elements of a Reliability Standard are the Requirements, and, if
properly drafted, a Reliability Standard may be enforced even in the
absence of specified Measures or Levels of Non-Compliance.\120\ Thus,
the NOPR proposed to approve a Reliability Standard even though it may
lack 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 would be improved
by providing missing Measures or Levels of Non-Compliance or by
clarifying ambiguities with respect to Measures or Levels of Non-
Compliance, the NOPR proposed to approve the Reliability Standard and
concurrently direct NERC to modify the Reliability Standard
accordingly.
---------------------------------------------------------------------------
\120\ NOPR at P 105-07.
---------------------------------------------------------------------------
240. The NOPR explained that the common format of NERC's proposed
Reliability Standards calls for a ``data retention'' metric. Yet, some
proposed Reliability Standards either do not contain a data retention
requirement or state that no record retention period applies. In the
NOPR, the Commission requested comment on: (1) Whether the retention
time periods specified in various Reliability Standards proposed by
NERC are sufficient to foster effective enforcement and (2) what, if
any, additional records retention requirements should be established
for the proposed Reliability Standards.
a. Improving Measures and Levels of Non-Compliance
i. Comments
241. A number of commenters raise concerns regarding the adequacy
of current Measures and Levels of Non-Compliance. Some commenters, such
as Nevada Companies, state that some Reliability Standards do not need
multiple Measures and multiple Levels of Non-Compliance when such items
do not fit the context of the specific Reliability Standard. According
to Nevada Companies, some proposed Reliability Standards are more like
business practices that are susceptible to a pass/fail test, and are
not necessarily amenable to multiple Measures and Levels of Non-
Compliance. Progress and Xcel maintain that Measures and Levels of Non-
Compliance do not necessarily need to be added to every Reliability
Standard.
242. Constellation is concerned that the Levels of Non-Compliance
do not appear to be based on objective criteria, but rather appear to
be based on arbitrary criteria and assumptions regarding the impact on
reliability, which could lead to penalties that are excessive compared
to the violation. MISO states that the original intent of the Levels of
Non-Compliance was to assign a scale based on the impact on the
Interconnection. MISO asserts that many Requirements are rated at too
high a level and that many events that would be rated ``level 4'' are
really just administrative requirements. It asserts that there are more
``level 4'' events than other categories, when logic would imply a
pyramid structure with only a few items at the highest ``level 4.''
MISO states there should be a simplified process that measures the true
impact on reliability. MISO and Dynegy state that there should also be
an ``administrative infraction'' category created in addition to the
current ``low,'' ``medium'' and ``high,'' so that the enforcement of
supporting tasks can be handled expeditiously.
243. NYSRC states that, in NERC's rush to file with the Commission
the 20 revised Reliability Standards with new Measures and Levels of
Non-Compliance, the revised Reliability Standards were submitted to the
NERC ballot body as a group, rather than individually. It maintains
that the group treatment prevented stakeholders from providing the
careful attention that each revised Reliability Standard deserves.
NYSRC believes that, as a result, Requirements for a number of these
Reliability Standards are flawed. While their prompt approval may be
justified to have them in place for the upcoming summer, there is not a
sufficient basis for the Commission to conclude that the weaknesses
identified in these 20 Reliability Standards have been adequately
addressed. NYSRC recommends that the Commission approve the 20 revised
Reliability Standards and direct the ERO to more carefully address the
weaknesses identified in those standards and to individually submit
each revised standard to a ballot for separate consideration.
244. MISO, International Transmission and Constellation also raise
concerns with NERC's Violation Risk Factors. They are concerned that
risk is, in some cases, being confused with importance. For example,
MISO states that NERC appears to be assigning risk to every sentence in
each proposed Reliability Standard, including explanatory information
and administrative requirements, thereby confusing risk with
importance. MISO states that, while there may be many things that a
transmission operator does that are important, failure to do an
important thing one time would not necessarily jeopardize the
Interconnection or cause a cascading failure.
245. MISO believes the definition of risk should reflect the
likelihood that something serious is likely to happen if an event
occurs. International Transmission, Constellation and MISO believe that
a high risk event should, in and of itself, pose a significant threat
to reliability and should not assume that multiple events occur
simultaneously. According to MISO, only a small number of Requirements
in the Reliability Standards fit the true definition of high risk.
Constellation maintains that rating too many Requirements as high risk
will water down the Requirements, and could shift the focus of
attention away from the truly high risk Requirements, leading to a less
effective, less efficient reliability program.
[[Page 16444]]
ii. Commission Determination
246. With regard to the comments of Nevada Companies, Progress and
others, we believe that the ERO should have flexibility in initially
developing appropriate Measures and Levels of Non-Compliance. For
example, the ERO in the first instance should determine whether a
Measure is necessary for every Requirement of a particular Reliability
Standard, or whether every Reliability Standard must have the same
number of Levels of Non-Compliance. Entities interested in developing
meaningful Measures and Levels of Non-Compliance should, we find,
participate in the ERO's Reliability Standards development process to
ensure that their opinions are considered.
247. With regard to the concerns of MISO and Constellation, we
agree as a general principle that Levels of Non-Compliance should be
based on objective criteria and that a ``level 4'' violation should
reflect a commensurate level of severity in its impact on Bulk-Power
System reliability. However, we will allow the ERO in the first
instance to determine whether specific revisions to particular
Reliability Standards are needed to address these concerns. While we
consider the appropriateness of Measures and Levels of Non-Compliance
in our standard-by-standard review, we believe in the first instance it
is the responsibility of the ERO to develop meaningful Measures and
Levels of Non-Compliance, and those seeking to influence the process,
as we have already found, should participate in the ERO's Reliability
Standards development process. Likewise, we leave it to the ERO to
determine initially whether there is any merit in developing a category
of ``administrative infraction'' as suggested by some commenters.
248. The Commission agrees with NYSRC that, as a general matter,
each Reliability Standard should be independently balloted in the
Reliability Standards development process. However, the Commission will
not require the ERO to resubmit each of the 20 revised Reliability
Standards to the Reliability Standards development process for separate
consideration. We do not believe such an action is required by the
statute and would otherwise unnecessarily delay implementation of the
proposed Reliability Standards. However, we expect that the ERO's
Reliability Standards development process will provide adequate
opportunity for independent consideration by stakeholders of each
standard under consideration in the future.
249. MISO, International Transmission and Constellation raise
concerns with NERC's Violation Risk Factors. The NERC board approved
the Violation Risk Factors for Version 0 Reliability Standards and
submitted them to the Commission on February 23, 2007. The Commission
is reviewing the Violation Risk Factors in a seprate proceeding in
Docket No. RR07-9-000. Thus, these issues are not ripe for
consideration in this Final Rule. MISO, International Transmission and
Constellation may raise concerns they have with the Violation Risk
Factors in that separate proceeding.
b. Enforcement Implications
i. Comments
250. Certain commenters, such as EEI, Northeast Utilities, APPA and
TAPS, state that Reliability Standards that lack clear Measures or
Levels of Non-Compliance should not be fully enforced because they are
not just and reasonable and raise potential due process concerns. APPA
states that this is equally true of Reliability Standards that lack
Violation Risk Factors or Violation Severity Levels because there is
not proper notice as to the amount or range of monetary penalties to be
assessed for a particular violation. APPA recommends that the
Commission approve Reliability Standards that lack Measures and
Violation Severity Levels, but that, until the deficiencies are
corrected, require NERC and Regional Entities to waive imposition of
monetary penalties. APPA would, however, reserve the Commission's right
to impose monetary sanctions where warranted and also require
compliance with NERC and Regional Entity remedial action directives for
these Reliability Standards.
251. WIRAB disagrees that Reliability Standards can be consistently
enforced based solely on sufficiently clear and enforceable
Requirements. According to WIRAB, Levels of Non-Compliance are needed
to inform parties of the consequences of non-compliance. WIRAB is
concerned that a complex penalty structure that requires Regional
Entities to consider multiple subjective mitigating and aggravating
factors will compound the problems of missing and ambiguous Measures
and Levels of Non-Compliance. A simple penalty structure would reduce
enforcement ambiguities, increase uniformity and promote greater
clarity. FirstEnergy states that, without Measures and Levels of Non-
Compliance, a Reliability Standard cannot meet the Commission's
requirement that a Reliability Standard must have a ``clear criterion
or measure of whether an entity is in compliance with a proposed
Reliability Standard.'' \121\
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\121\ FirstEnergy at 10-11, citing NOPR at P 16; see also Order
No. 672 at P 262, 321-37.
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252. Progress and Xcel state that the Commission should clarify
that the Measures and Levels of Non-Compliance are included solely for
guidance and that only violations of the Requirements are subject to
penalties. Portland General maintains that the Measures are an integral
part of each Reliability Standard because entities will need to know
the Measures so that they can build them into their compliance efforts
from the beginning. In a similar vein, National Grid states that the
lack of clear Measures or Levels of Non-Compliance also makes it
difficult for users, owners and operators to tailor their businesses
and practices toward compliance or to track ongoing compliance.
ii. Commission Determination
253. The Commission disagrees with commenters that a Reliability
Standard cannot reasonably be enforced, or is otherwise not just and
reasonable, solely because it does not include Measures and Levels of
Non-Compliance. The Commission adopts the position it took in the NOPR
that, 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 given
the specific facts and circumstances of its use, ownership or operation
of the Bulk-Power System. As we explained in the NOPR, and reiterate
here:
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.'' If properly drafted, a Reliability Standard may be
enforced in the absence of specified Measures or Levels of Non-
Compliance.\122\
\122\ NOPR at P 105 (footnote omitted).
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254. APPA, WIRAB and others contend that, without Measures and
Levels of Non-Compliance, a Reliability Standard should not be
enforced. We disagree. Where a Reliability Standard has Requirements
that are sufficiently clear so that an entity is aware of what it must
do to comply, sufficient notice has been provided. While it can be
helpful to provide additional guidance
[[Page 16445]]
regarding the amount or range of monetary penalties that may be
assessed for a particular violation, the absence of such information is
not a defect that renders a Reliability Standard unenforceable. Where
the Requirement in a Reliability Standard is sufficiently clear, an
entity will know what it should be doing to comply and will know that
there are consequences for failure to comply. Therefore, where a
Requirement in a Reliability Standard is sufficiently clear, we approve
the Reliability Standard even though it may lack Measures or Levels of
Non-Compliance. Where a Reliability Standard can 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
approve the Reliability Standard and concurrently direct NERC to modify
it accordingly.\123\
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\123\ APPA raises concerns regarding the completeness or
adequacy of Measures and Levels of Non-Compliance in its discussion
of specific Reliability Standards. In such instances, APPA argues
that the Reliability Standard should not be enforced until current
Measures and Levels of Non-Compliance are improved or, where
incomplete, new ones developed. Applying our above rationale to
these particular circumstances, while the ERO should improve or
develop Measures and Levels of Non-Compliance where necessary, we
will not delay the enforcement of such Reliability Standards until
the ERO develops such improvements or additions.
---------------------------------------------------------------------------
255. In response to FirstEnergy, where the Requirement in a
Reliability Standard is sufficiently clear, that Reliability Standard
meets the requirement that it must have a ``clear criterion or measure
of whether an entity is in compliance with a proposed Reliability
Standard.'' The fact that NERC, in certain circumstances, did not
include Measures and Levels of Non-Compliance does not make an
otherwise clear Requirement unenforceable. Neither section 215 nor the
Commission's regulations require the level of specificity sought by
FirstEnergy in order for a Reliability Standard to be enforceable.
256. Progress and Xcel seek clarification that Measures and Levels
of Non-Compliance are included solely for guidance and that only
violations of the Requirements are subject to penalties. While the
Commission generally agrees that it is a violation of the Requirements
that is subject to a penalty, we recognize that because Measures are
intended to gauge or document compliance, failure to meet a Measure is
almost always going to result in a violation of a Requirement.
257. While we applaud NERC for adding additional levels of detail
to its compliance enforcement program, we note that NERC and the
Regional Entities should have further guidance as to how to use their
enforcement discretion from the Commission's Policy Statement on
Enforcement.\124\ Further, if NERC does not submit Violation Risk
Factors and Violation Severity Levels before NERC's enforcement program
becomes effective, the Commission has reserved the ability to take
appropriate action to ensure that the penalty-setting process described
in the Sanction Guidelines is operative.\125\
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\124\ Enforcement of Statutes, Orders, Rules, and Regulations,
113 FERC ] 61,068 (2005) (Policy Statement on Enforcement).
\125\ January 2007 Compliance Order at P 93.
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c. Data Retention
i. Comments
258. In the NOPR, the Commission solicited comments regarding the
sufficiency of data retention requirements in the Reliability
Standards.\126\ NERC states that the compliance data retention
requirement is a defined element in the Reliability Standard template
and that all data retention requirements, even those that are currently
missing, will be reviewed and updated as part of the Reliability
Standards Work Plan. NERC requests that the Commission not attempt to
fix specific data retention requirements on the basis of comments
received during this proceeding. NERC would prefer that the Commission
direct those comments and any goals the Commission may have with regard
to data retention back to NERC for resolution through the Reliability
Standards development process.
---------------------------------------------------------------------------
\126\ NOPR at P 107.
---------------------------------------------------------------------------
259. SoCal Edison supports the data retention requirements in the
Reliability Standards. APPA and SERC recommend that data retention
requirements should be stated in each Reliability Standard and
determined on a case-by-case basis through the Reliability Standards
development process.
260. SERC agrees with NERC that an appropriate retention period is
five years unless otherwise specified in a Reliability Standard. ISO-NE
submits that any data retention policy established by the ERO should be
in line with the five year civil penalty statute of limitations for
violations of NERC Standards, while APPA cautions that detailed
operational data may be so voluminous that a five-year retention
requirement would be burdensome and of questionable value. MRO believes
that the Reliability Standards retention period should be commensurate
with operating and planning horizons, documentation related to a
planning standard should be retained longer and that there should be a
retention period of at least three years.
261. FirstEnergy states that individual record retention
requirements on a standard-by-standard basis will create confusion and
will be difficult to track. It therefore suggests that the Commission
establish a uniform records retention standard of ``current calendar
year plus three years'' for all proposed Reliability Standards that
include a data retention requirement. Similarly, Entergy states that
data retention requirements established for the Reliability Standards
should be uniform and asks the Commission to direct the ERO to
implement records retention requirements of no longer than three years.
262. International Transmission and Entergy comment that only the
relevant core reliability requirements of the Reliability Standards
should be subject to data retention requirements. International
Transmission states that, in instances where retaining evidence of
compliance is impractical or where no evidence exists of compliance, it
is appropriate that no documentation be retained. Otherwise the record
retention period should be no less than the prevailing audit frequency.
Progress and Xcel agree that inclusion of data retention metrics in the
Reliability Standards would be useful, but the Commission should make
clear that violations of the data retention metrics are not subject to
separate penalties under section 215 of the FPA.
ii. Commission Determination
263. The Commission agrees that it is appropriate for each
Reliability Standard to have a data retention requirement. We are not
persuaded that a one-size fits all approach to data retention is
appropriate, however, because different Reliability Standards may
require data to be retained for shorter or longer periods. Nor are we
persuaded that the Commission should set a data retention requirement
for any Reliability Standard for which one is currently lacking.
Therefore, the Commission will not prescribe a set data retention
period to apply to all Reliability Standards. Instead, the Commission
directs the ERO to review and update the data retention requirements in
each Reliability Standard as it is reevaluated through its Reliability
Standards development process and submit the result for Commission
approval. In doing so, NERC should take into account the comments
raised in this proceeding and should seek input from other industry
stakeholders.
[[Page 16446]]
3. Ambiguities and Potential Multiple Interpretations
264. In the NOPR, the Commission proposed that a proposed
Reliability Standard that has Requirements that are so ambiguous as to
not be enforceable should be remanded.\127\ A Reliability Standard that
has sufficiently clear Requirements, Measures and Levels of Non-
Compliance language and otherwise satisfies the statutory standard of
review should be approved. A proposed Reliability Standard that has
sufficiently clear 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 Levels of Non-Compliance language. 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, the
Commission proposed to adopt that interpretation in the NOPR.
---------------------------------------------------------------------------
\127\ NOPR at P 110-12.
---------------------------------------------------------------------------
a. Comments
265. NERC maintains that, even if the Commission believes that
there is some degree of ambiguity in some of the Reliability Standards,
making the Reliability Standards mandatory enables NERC and Regional
Entities to respond to questionable performance by clarifying to the
responsible entity, and others, on a going-forward basis what behavior
would constitute compliance with the Reliability Standards. Thereafter,
participants would know how NERC and the Regional Entities were
interpreting the Reliability Standards. According to NERC, this
information would become part of the public record and help to
eliminate any ambiguity as to what constitutes compliant and
noncompliant behavior under a Reliability Standard. In contrast, if the
Reliability Standards remain voluntary or temporarily unapproved, NERC
contends that it and the Regional Entities will lack a legal basis to
compel corrective behavior.
266. In contrast, Reliant urges the Commission to either not
approve ambiguous Reliability Standards or approve them without
subjecting entities to penalties. The level of ambiguity in many cases
appears to violate the ``just and reasonable'' criteria for approval.
It states that entities should not be found in violation based on
retroactive interpretation of a Reliability Standard.
267. EEI expresses concern that approval and enforcement of a
Reliability Standard that includes ambiguous requirements or lacks
certain technical features or specificity may raise due process
concerns if the required performance or performance measurements are
not ``clear and unambiguous.'' Both in this docket and on a going
forward basis, EEI questions whether proposed Reliability Standards
with various shortcomings or deficiencies are sufficiently clear to
meet the legal standard of review.
268. EEI and Wisconsin Electric state that it is not clear what
``common interpretations'' the Commission refers to in the NOPR or
whether they are accepted or known across the industry. Wisconsin
Electric states that common interpretations and best practices must be
clearly spelled out and made available for review. These
interpretations should be incorporated into the audit guidelines.
Further, EEI states that common interpretations should not supersede
provisions that are clearly stated in a Reliability Standard. According
to EEI, if part of a proposed Reliability Standard is not clear, the
NERC Reliability Standards development process should be used to
clarify it. Further, EEI maintains that the Commission should require
the ERO to review all existing industry sources, such as the NERC
glossary or Institute of Electrical and Electronics Engineers (IEEE)
standards, to supplement the interpretation of Reliability Standards.
Undocumented ``common interpretations'' should be relied on only as a
last resort. Moreover, EEI contends that, if such interpretations are
to be used as a basis for assessing compliance and enforcement, they
must be clearly spelled out and made available in advance.
269. MISO notes that some Reliability Standards may have portions
applicable to five or more entities and that there are situations where
a particular functional entity is not mentioned in the
``Applicability'' section of the Reliability Standard, but they show up
in the Requirements. It believes that the industry needs a database-
style tool that is a companion to the Reliability Standards that
permits any functional entity to sort and find all requirements and
supporting compliance information applicable to it. Such a tool would
help entities prevent oversights and also help NERC eliminate
redundancy in the Reliability Standards.
270. MISO also states that, in developing the Version 0 Reliability
Standards, there was a conscious decision to include supporting
information in the Reliability Standards themselves. As a result, there
is now explanatory material in the Reliability Standards that is
presented in context as Requirements. According to MISO, users now are
trying to figure out how to measure Requirements that are really
supporting text. MISO believes that the process should be simplified by
separating each Reliability Standard into its core requirements and
supporting information.
271. Similarly, Constellation, International Transmission and
Dynegy comment that the Commission should distinguish between those
Requirements in each Reliability Standard that are core requirements as
opposed to supporting information, an explanatory statement, or an
administrative process. International Transmission and Dynegy state
that Measures should only apply to these core reliability requirements.
Reliant is also concerned that each Reliability Standard contains a
great deal of explanatory text, formatted to appear as enforceable
obligations.
272. International Transmission, Reliant and MISO note that the
proposed Reliability Standards contain many inherently ambiguous
phrases or terms that can be misapplied, including ``adequate'' or
``adequately,'' ``sufficient,'' ``immediate,'' ``where technically
feasible,'' ``as soon as possible'' and ``where practical.'' Reliant
states that all ambiguous language must be eliminated before penalties
can be assessed. MISO and Wisconsin Electric state that, while use of
such terms may be acceptable in explanatory information, if a term
cannot be definitively and objectively defined, it should not appear in
the core Requirements of a Reliability Standard.
273. Alcoa reiterates its concern that the Commission has not
defined the target level of reliability of the Bulk-Power System that
the Reliability Standards are intended to achieve. Further, Alcoa is
concerned that the proposed Reliability Standards are fragmented and
overlap and in some cases may result in inconsistent treatment of the
same issue. Alcoa states that the ERO should move towards a more
encompassing approach for developing Reliability Standards in which a
reliability goal is addressed from all aspects in a more consistent
manner. Therefore, Alcoa maintains that the Commission should require
NERC to engage in advance planning, mapping out what kind of
reliability is adequate for the Bulk-Power System and then developing a
plan to get there.
b. Commission Determination
274. The Commission finds that it is essential that the
Requirements for each Reliability Standard, in particular, are
sufficiently clear and not subject to
[[Page 16447]]
multiple interpretations. Where the Requirements portion of a
Reliability Standard is sufficiently clear (and no other issues have
been identified), we approve the Reliability Standard. Upon review of
the Reliability Standards and the comments submitted in response to the
NOPR, the Commission finds that none of the Reliability Standards that
we approve today contain an ambiguity that renders it unenforceable or
otherwise unjust and unreasonable. As discussed in our standard-by-
standard review, each Reliability Standard that we approve contains
Requirements that are sufficiently clear as to be enforceable and do
not create due process concerns.
275. The underlying assumption of many of the commenters seems to
be that the Reliability Standards must spell out in minute detail all
factual scenarios that might violate a Requirement and the precise
consequences of that violation. But due process requirements do not go
so far. Indeed, many government regulatory schemes provide far less
specificity in terms of what is required or proscribed, and yet those
regulations are routinely enforced.\128\ Indeed, many tariffs on file
with the Commission do not specify every compliance detail, but rather
provide some level of discretion as necessary to carry out a particular
act. This does not mean the tariffs are unenforceable; rather, it means
that, if a dispute arises over compliance and there is a legitimate
ambiguity regarding a particular fact or circumstance, that ambiguity
can be taken into account in the exercise of the Commission's
enforcement discretion. Therefore, we find that the Reliability
Standards must strike a balance between a level of specificity that
places users, owners and operators on notice of what is required, and a
level of generality that encompasses unanticipated but serious actions
or omissions that could affect Bulk-Power System reliability. We are
satisfied that the Requirements portions of each Reliability Standard
that we approve in this Final Rule appropriately strike this balance.
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\128\ Many sections of the FPA, including section 215, use such
terms as just and reasonable or unduly discriminatory or
preferential or even the public interest.
---------------------------------------------------------------------------
276. Some commenters argue that certain Reliability Standards
require additional specificity or else users, owners and operators will
not understand the consequences of a violation. This notion is
similarly misplaced because the potential (if not actual) consequences
for any violation are clearly spelled out--the statute permits the ERO
to assess civil penalties of up to ``$1 million per violation, per
day'' in addition to other remedies. The Commission has explained how
it will approach civil penalties in its Enforcement Policy Statement.
The ERO has provided guidance in its compliance filings, and will
continue to do so, as to how it will administer compliance and
enforcement functions. Clarity should not be confused with certainty.
The former is provided by the statute, the Final Rule and the
aforementioned authorities. The latter is simply unavailable in this
context. Indeed, guaranteeing in advance specific enforcement outcomes
hampers necessary and appropriate enforcement flexibility and poses the
danger of users, owners and operators of the Bulk-Power System simply
calculating the cost of a violation into the cost of doing business--a
dynamic that would frustrate the very purpose of a mandatory
Reliability Standards system, which is to promote reliability.
277. The Commission agrees with NERC that, even if some
clarification of a particular Reliability Standard would be desirable
at the outset, making it mandatory allows the ERO and the Regional
Entities to provide that clarification on a going-forward basis while
still requiring compliance with Reliability Standards that have an
important reliability goal. Further, we support the ERO's efforts to
review each of the current Reliability Standards to improve them and
provide yet further clarity. We encourage all interested entities,
especially those that have identified specific suggestions for
improvement, to participate in the ERO's Reliability Standards
development process.
278. The Commission finds that these Reliability Standards, with
the interpretations provided by the Commission in the standard-by-
standard discussion, meet the statutory criteria for approval as
written and should be approved. In any event, penalties are warranted
under section 215 only when an entity knew or reasonably should have
known that its acts or omissions were contrary to the Reliability
Standards. Wisconsin Electric seems to interpret the Commission as
requiring that users, owners and operators of the Bulk-Power System
comply with best practices under the Reliability Standards. We
disagree. While we appreciate that many entities may perform at a
higher level than that required by the Reliability Standards, and
commend them for doing so, the Commission is focused on what is
required under the Reliability Standards; we do not require that they
exceed the Reliability Standards. We agree with EEI that a common
interpretation cannot supplant a provision that is clearly stated in a
Reliability Standard. We also agree, however, that, over time, these
interpretations could be incorporated either into the Reliability
Standard itself through the Reliability Standards development process
or the ERO and Regional Entity audit guidelines.
279. The Commission disagrees with MISO that some Reliability
Standards as proposed are unclear with respect to applicability. In
certain situations, Bulk-Power System reliability depends on more than
one entity complying with a Reliability Standard. Further, in certain
situations, the Requirement of a Reliability Standard may reference an
entity that is not itself responsible for compliance with the
Reliability Standard, for example, where an entity responsible for
compliance must report information to or communicate with another
entity, without that other entity being required to comply with the
Reliability Standard. However, in its review of Reliability Standards,
the ERO should ensure that, if a functional entity must comply with the
Reliability Standards, it must be mentioned in the Applicability
section. In this regard, we encourage the ERO to consider development
of a database-style tool that is a companion to the Reliability
Standards that permits any user, owner or operator to sort and find all
Requirements applicable to it.
280. In response to MISO, Constellation, International Transmission
and Dynegy, the Commission believes that the Requirements in each
Reliability Standard are core obligations and that the Measures and
Levels of Non-Compliance provide useful guidance to the industry and
can be supporting information, an explanatory statement or an
administrative process. As discussed above, NERC is to enforce the
Requirements in a Reliability Standard. The Measures are part of the
Reliability Standards and, if not met, are almost always going to
result in a violation of a Requirement.
281. The Commission has previously addressed Alcoa's concerns about
defining the target level of reliability of the Bulk-Power System that
the Reliability Standards are intended to achieve. In the January 2007
Compliance Order, the Commission directed the ERO to establish a
stakeholder process to define adequate level of reliability.\129\ While
the Commission agrees that this is a worthwhile effort, we disagree
with
[[Page 16448]]
Alcoa that Reliability Standards cannot be approved until this analysis
is done. Such analysis is not required by the statute, and Alcoa has
not identified any compelling reason why the proposed Reliability
Standards are defective without the benefit of such analysis.
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\129\ January 2007 Compliance Order at P 16.
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4. Technical Adequacy
282. In the NOPR, we stated that 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.
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.\130\
---------------------------------------------------------------------------
\130\ NOPR at P 115.
---------------------------------------------------------------------------
a. Comments
283. NYSRC shares the Commission's concerns regarding the use of a
``lowest common denominator'' approach in the development of
Reliability Standards and agrees that this concern can be addressed
only on a standard-by-standard basis. NYSRC maintains that, in
commenting on pending ERO Reliability Standards, the NYSRC believed
could weaken existing Reliability Standards, the NERC drafting team
responded that a region is free to develop more stringent Reliability
Standards. NYSRC maintains that the ability of a Regional Entity to
propose more stringent Reliability Standards to meet the reliability
needs of that region does not justify the weakening of continent-wide
Reliability Standards by use of a ``lowest common denominator''
approach to achieve greater support for a proposed Reliability
Standard. NYSRC recommends that the Commission reaffirm that it will
carefully review subsequent proposed ERO Reliability Standards to
ensure that they are technically adequate and do not weaken the current
level of reliability.
284. ATC agrees with the Commission that the industry, organized in
Regional Entities under the ERO, must continue to be wholly accountable
for the technical adequacy of the Reliability Standards. ATC thus
suggests that the Commission's efforts to ``independently assess the
technical adequacy of any proposed Reliability Standard'' focus on
Commission participation in and support of the Reliability Standards
development processes at NERC and at the regions.
b. Commission Determination
285. The Commission fully intends to address technical adequacy on
a standard-by-standard basis and the Commission agrees that the ability
of a Regional Entity to propose more stringent Reliability Standards to
meet the reliability needs of that region does not justify the
weakening of continent-wide Reliability Standards. In this regard, we
note that, in the January 2007 Compliance Order, we directed the ERO to
closely monitor the voting results for Reliability Standards and to
report to us quarterly for the next three years its analysis of the
voting results, including trends and patterns that may signal a need
for improvement in the voting process, such as the rejection of a
Reliability Standard and subsequent ballot approval of a less stringent
version of the Reliability Standard.\131\ The Commission will use this
information to evaluate whether it needs to re-examine the Reliability
Standard development procedure. In doing so, the Commission will also
be sensitive to concerns that ``lowest common denominator'' Reliability
Standards are being developed.
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\131\ January 2007 Compliance Order at P 18.
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286. The Commission agrees that its staff should participate in and
support the Reliability Standards development processes, to the extent
consistent with its regulatory role. The Commission's participation in
those processes will not constitute its entire assessment of the
technical adequacy of a proposed Reliability Standard. The Commission
will also conduct an assessment during its rulemaking or order process
after the Reliability Standard is submitted by the ERO to the
Commission for approval.
5. Fill-in-the-Blank Standards
287. The NOPR explained that certain Reliability Standards,
referred to as fill-in-the-blank standards, require the regional
reliability organizations to develop criteria for use by users, owners
or operators within each region.\132\ In the NOPR, the Commission
expressed concern regarding the potential for the fill-in-the-blank
standards to undermine uniformity. With regard to NERC's stated
intention to submit an action plan and schedule for completing the
fill-in-the-blank standards, the NOPR explained that NERC's plan must
be consistent with the discussion in Order No. 672 regarding uniformity
and the limited circumstances in which a regional difference would be
permitted.\133\
---------------------------------------------------------------------------
\132\ NOPR at P 116.
\133\ Id. at P 121, citing Order No. 672 at P 292; ERO
Certification Order at P 274.
---------------------------------------------------------------------------
288. Further, the NOPR proposed to require supplemental information
regarding any Reliability Standard that requires a regional reliability
organization to fill in missing criteria or procedures. The Commission
explained that, ``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.'' \134\ Therefore, the NOPR
proposed to not approve or remand such Reliability Standards until all
necessary information is provided, although compliance would still be
expected as a matter of good utility practice.
---------------------------------------------------------------------------
\134\ NOPR at P 123.
---------------------------------------------------------------------------
a. Comments
289. NERC, APPA and TAPS support the Commission's proposal to defer
consideration of fill-in-the-blank standards. APPA believes that the
Commission's proposal balances the need for greater uniformity against
the need for regional flexibility.
290. NERC agrees with the Commission's proposal to hold 24
Reliability Standards (mainly fill-in-the-blank standards) as pending
at the Commission until further information is provided, and to require
that Bulk-Power System users, owners and operators follow these pending
standards as ``good utility practice'' pending their approval by the
Commission. NERC also agrees that it and the Regional Entities can
monitor compliance with these pending standards using the ERO's
authority pursuant to Sec. 39.2(d) of the Commission's regulations.
NERC believes this approach is necessary to ensure that there will be
no gap during the transition from the current voluntary reliability
regime to mandatory and enforceable Reliability Standards.
291. While TAPS supports deferring consideration of fill-in-the-
blank standards, it urges the Commission to view with skepticism
regional differences within an Interconnection that are not justified
by physical differences. It states that such regional Reliability
Standards, even if more stringent, can wreak havoc on competitive
markets, especially where entities within the same transmission system
or RTO footprint are subject to different regional Reliability
Standards. For example, TAPS maintains that inconsistent regional
underfrequency load shedding (UFLS) Reliability Standards not justified
by physical differences impose unjust burdens on joint action agencies
whose integrated load is split between NERC regions. Further, according
to TAPS, a region's
[[Page 16449]]
choice may reflect the historical lack of a balanced process for
developing Reliability Standards at the regional level, allowing
certain classes of market participants to determine the region's
choice.
292. According to ISO-NE, if the Commission withholds approval of
these 24 Reliability Standards, the Commission should also withhold
approval of Reliability Standards that rely, by reference, on such
fill-in-the-blank Reliability Standards.\135\ ISO-NE submits that,
until the missing information has been provided in the cross-referenced
fill-in-the-blank Reliability Standard, it will be impossible for the
applicable entities to determine exactly what criteria they are
expected to satisfy. APPA raises similar concerns, and suggests that
the Commission approve such Reliability Standards but not enforce them
until the cross-referenced fill-in-the-blank Reliability Standards are
approved.
---------------------------------------------------------------------------
\135\ ISO-NE and ISO/RTO Council state that the following
Reliability Standards are dependent upon ``fill-in-the-blank''
standards: FAC-013-1, MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0,
MOD-018-0, MOD-019-0, MOD-021-0, PRC-004-1, PRC-007-0, PRC-008-0,
PRC-009-0, PRC-015-0, PRC-016-0, PRC-018-1 and PRC-021-0.
---------------------------------------------------------------------------
293. MISO and Wisconsin Electric believe that the fill-in-the-blank
standards may be acceptable in certain situations. They give regions
some flexibility in implementation, and allow the deployment of a
Reliability Standard where it would be difficult to get consensus
across several regions. They also move the reliability agenda forward
on issues that are historically under state jurisdiction, and some are
an accommodation to those regions that want to have a higher
Reliability Standard.
294. EEI agrees with the NOPR that, regarding Reliability Standards
for which the Commission needs additional information, compliance in
the interim would be expected as a matter of good utility practice.
While EEI agrees with this approach, it also cautions that the good
utility practice provision of an OATT should not be used as an
alternative means of enforcement outside of section 215 of the FPA.
Similarly, FirstEnergy posits that good utility practice is subject to
interpretation and by itself does not provide the level of guidance
needed for a mandatory and enforceable Reliability Standard. It asserts
that the Commission should not impose compliance burdens indirectly
where it has not imposed them directly. Xcel asserts that the
Commission should rescind the Reliability Policy Statement that defines
good utility practice under the pro forma OATT, effective when the
Reliability Standards become mandatory in June 2007, because a
reliability-related violation should not be subject to two separate
enforcement schemes.
295. NPCC recommends that any of the 24 fill-in-the-blank standards
that are required to be Reliability Standards should be developed as
regional Reliability Standards by the Regional Entity for compliance
monitoring and enforcement, backed by the Commission and Canadian
provincial regulatory and/or governmental authorities.
296. California PUC states that the NOPR seeks national uniformity
notwithstanding regional differences. It states that, in the Western
Interconnection, there are 15 existing, enforceable WECC standards
pursuant to the WECC Reliability Management System (RMS) that overlap
the proposed mandatory Reliability Standards. Five of these WECC
standards fall into the fill-in-the-blank standards category. However,
there are three additional WECC RMS standards already in effect in the
Western Interconnection that do not have a corresponding proposed
Reliability Standard. California PUC asks that the Commission consider
approving these additional three standards for enforcement in the
Western Interconnection. California PUC states that there is no reason
for the Commission to exclude any WECC standard already in effect, and
that ignoring these established standards when the Reliability
Standards are scheduled to go into effect can threaten reliability
already being achieved in the Western Interconnection.
b. Commission Determination
297. The Commission requires supplemental information for any
Reliability Standard that currently requires a regional reliability
organization to fill in missing criteria or procedures. Where important
information has not yet been provided to us to enable us to complete
our review, we are not in a position to approve or remand those
Reliability Standards.\136\ Accordingly, we will not approve or remand
such Reliability Standards until the ERO submits further information.
Until such information is provided, compliance with fill-in-the-blank
standards should continue on a voluntary basis, and the Commission
considers compliance with such Reliability Standards to be a matter of
good utility practice.
---------------------------------------------------------------------------
\136\ NOPR at P 123.
---------------------------------------------------------------------------
298. As noted above, some commenters such as TAPS urge the
Commission to view most regional differences with skepticism, while
others such as MISO and Wisconsin Electric favor some regional
variation. The Commission affirms the approach that it articulated in
the NOPR.\137\ We share commenters' concerns regarding the potential
for fill-in-the-blank standards to undermine uniformity. While
uniformity is the goal with respect to Reliability Standards, we
recognize that it may not be achievable overnight. Over time, we would
expect that the regional differences will decline and uniform and best
practices will develop. In Order No. 672, the Commission identified two
instances where regional differences may be permitted, i.e., regional
differences that are more stringent than continent-wide Reliability
Standards (including those that address matters not addressed by a
continent-wide Reliability Standard) and a regional difference
necessitated by a physical difference in the Bulk-Power System.
---------------------------------------------------------------------------
\137\ Id. at P 121 (footnote omitted).
---------------------------------------------------------------------------
299. The ERO should develop the needed information for the
Commission to act on the fill-in-the-blank standards consistent with
these criteria. If a regional difference is warranted, a regional fill-
in-the-blank proposal must be developed through an approved regional
Reliability Standards development process, and submitted to the ERO. If
approved by the ERO, the ERO will then submit it to the Commission for
approval.
300. The Commission disagrees with ISO-NE, ISO/RTO Council and APPA
that 16 additional Reliability Standards should not be acted on or
enforced at this time. The fact that a Reliability Standard simply
references another, pending Reliability Standard, one that is not being
approved or remanded here, does not alone justify not approving the
former Reliability Standard. Rather, such a reference may be considered
in an enforcement action, if relevant, but is not a reason to delay
approval of enforcement of the Reliability Standard. We find that the
Reliability Standards that reference a pending Reliability Standard
contain the appropriate level of specificity necessary to provide
notice to users, owners and operators of the Bulk-Power System as to
what is required.
301. The Commission has reviewed the 16 Reliability Standards
identified by commenters as referencing a Reliability Standard that the
Commission proposed not to approve or remand. It appears that many of
these Reliability Standards either refer to the process of collecting
data or reference Requirements that entities are generally
[[Page 16450]]
aware of because they have already been following these Reliability
Standards on a voluntary basis. For example, MOD-012-0 requires
transmission and generator owners to provide data to the regional
reliability organization to support system modeling required by MOD-
013-0. The NOPR proposed not to approve or remand MOD-013-0 partly
because MOD-013-0 requires development of dynamics data requirements
and reporting procedures that have not been submitted for our review.
In addition, we proposed not to act on MOD-013-0 partly because it
applies to a regional reliability organization and the Commission was
not persuaded that a regional reliability organization's compliance
with a Reliability Standard can be enforced by NERC. That is not the
case with MOD-012-0, which applies to entities that are clearly users,
owners and operators of the Bulk-Power System. Although MOD-012-0
references MOD-013-0, its applicability to a subset of users, owners
and operators is not at issue. Accordingly, the Commission denies the
requests to leave pending this and similar data-related Reliability
Standards and reaffirms the NOPR approach described above.
302. While EEI and others agree with the proposal that, in the
interim, compliance with Reliability Standards for which the Commission
needs additional information should continue as a matter of good
utility practice, they caution that this should not lead to an
alternative means of enforcement outside of section 215 of the FPA. In
our Reliability Policy Statement, we explained that compliance with
NERC Reliability Standards (or more stringent regional standards) is
expected as a matter of good utility practice as that term is used in
the pro forma OATT.\138\ The Commission continues to expect compliance
with such Reliability Standards as a matter of good utility practice.
That being said, the Commission agrees that retaining a dual mechanism
to enforce Reliability Standards both as good utility practice and
under section 215 of the FPA is inappropriate; the OATT only applies to
entities subject to our jurisdiction as public utilities under the FPA,
while section 215 defines more broadly our jurisdiction with respect to
mandatory Reliability Standards. We therefore do not intend to enforce,
as an OATT violation, compliance with any Reliability Standard that has
not been approved by the Commission under section 215.
---------------------------------------------------------------------------
\138\ Policy Statement on Matters Related to Bulk Power System
Reliability, 107 FERC ] 61,052 at P 23-26 (2004) (Reliability Policy
Statement).
---------------------------------------------------------------------------
303. With regard to California PUC's comments, we recognize the
desire to retain certain existing regional standards that apply to the
Western Interconnection, which are currently enforceable pursuant to
WECC's RMS program. However, these regional Reliability Standards have
not been submitted to the Commission by the ERO pursuant to the process
set forth in Order No. 672. Accordingly, California PUC's concerns are
beyond the scope of this proceeding. The Commission will review the
WECC standards once they are approved by the ERO and submitted to the
Commission for approval.
F. Discussion of Each Individual Reliability Standard
304. The NOPR reviewed each proposed Reliability Standard and
provided an analysis by chapter according to the categories of
Reliability Standards defined in NERC's petition. Each chapter began
with an introduction to the category, followed by a discussion of each
proposed Reliability Standard. The Final Rule takes a similar approach.
1. BAL: Resource and Demand Balancing
305. The six Balancing (BAL) Reliability Standards address
balancing resources and demand to maintain interconnection frequency
within prescribed limits.
a. Real Power Balancing Control Performance (BAL-001-0)
306. 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. The proposed
Reliability Standard would apply to balancing authorities. In the NOPR,
the Commission proposed to approve BAL-001-0 as mandatory and
enforceable.\139\
---------------------------------------------------------------------------
\139\ NOPR at P 136.
---------------------------------------------------------------------------
i. Comments
307. APPA agrees with the Commission that BAL-001-0 is sufficient
for approval as a mandatory Reliability Standard.
ii. Commission Determination
308. For the reasons stated in the NOPR, the Commission approves
BAL-001-0 as mandatory and enforceable.
b. Regional Difference to BAL-001-0: ERCOT Control Performance Standard
2
309. NERC approved a regional difference for ERCOT by allowing it
to be exempt from Requirement R2 in BAL-001-0, which requires that the
average area control error (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. This Requirement is referred
to as Control Performance Standard 2 (CPS2).
310. NERC explains that ERCOT requested a waiver of CPS2 because:
(1) ERCOT, as a single control area \140\ 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 that it performed showing that under
the new market structure, the ten control areas in its region
individually were able to meet CPS2 standards while the aggregate
performance of the ten control areas was not in compliance. Since
requesting the waiver from CPS2, ERCOT has adopted section 5 of the
ERCOT protocols which identify the necessary frequency controls needed
for reliable operation in ERCOT.
---------------------------------------------------------------------------
\140\ 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.
---------------------------------------------------------------------------
311. In the NOPR, the Commission proposed to approve the ERCOT
regional difference and have the ERO submit a modification of the ERCOT
regional difference to include the requirements concerning frequency
response contained in section five of the ERCOT protocols.\141\
---------------------------------------------------------------------------
\141\ Id. at P 143.
---------------------------------------------------------------------------
i. Comments
312. No comments were filed on this regional difference.
ii. Commission Determination
313. The Commission approves the ERCOT regional difference as
mandatory and enforceable. Order No. 672 explains that ``uniformity of
Reliability Standards should be the goal and the practice, the rule
rather than the exception.'' \142\ 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.\143\ Regional differences must still be just, reasonable, not
unduly discriminatory or
[[Page 16451]]
preferential and in the public interest.\144\
---------------------------------------------------------------------------
\142\ Order No. 672 at P 290.
\143\ Id. at P 291.
\144\ Id.
---------------------------------------------------------------------------
314. The Commission finds that ERCOT's approach under section 5 of
the ERCOT protocols appears to be a more stringent practice than
Requirement R2 in BAL-001-0 and therefore approves the regional
difference.
315. As proposed in the NOPR, the Commission directs the ERO to
file a modification of the ERCOT regional difference to include the
requirements concerning frequency response contained in section 5 of
the ERCOT protocols. As with other new regional differences, the
Commission expects that the ERCOT regional difference will include
Requirements, Measures and Levels of Non-Compliance sections.
c. Disturbance Control Performance (BAL-002-0)
316. The stated purpose of this Reliability Standard is to use
contingency reserves to balance resources and demand to return
Interconnection frequency to within defined limits following a
reportable disturbance. The proposed Reliability Standard would apply
to balancing authorities, reserve sharing groups \145\ and regional
reliability organizations.
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\145\ 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 15.
---------------------------------------------------------------------------
317. In the NOPR, the Commission proposed to approve Reliability
Standard BAL-002-0 as mandatory and enforceable.\146\ In addition,
pursuant to section 215(d)(5) of the FPA and Sec. 39.5(f) of our
regulations, the Commission proposed to direct NERC to submit a
modification to BAL-002-0 that: (1) Includes a Requirement that
explicitly allows demand-side management (DSM) to be used as a resource
for contingency reserves; (2) develops a continent-wide contingency
reserve policy; \147\ (3) includes a Requirement that measures response
for any event or contingency that causes a frequency deviation; \148\
(4) substitutes the ERO for the regional reliability organization as
the compliance monitor and (5) refers to the ERO rather than the NERC
Operating Committee in Requirements R4.2 and R6.2.
---------------------------------------------------------------------------
\146\ NOPR at P 151.
\147\ The NOPR explained that this could be accomplished by
modifying Requirement R2 or developing a new Reliability Standard.
\148\ This proposed Requirement addressed modifications to
Requirement R3.1 which are described in the ``Disturbance Control
Standard and the Associated Reserve Requirement'' section of this
Final Rule.
---------------------------------------------------------------------------
i. General Comments
318. Constellation supports the Commission's proposals with respect
to BAL-002-0.
319. Xcel notes that this Reliability Standard would apply to a
reserve sharing group, which is not defined in the NERC Functional
Model but generally consists of a group of separate entities. Xcel
states it is not clear how compliance and penalties would be applied to
a reserve sharing group and seeks clarification from the Commission. As
a second concern, Xcel states it is not clear who calculates ACE
between a balancing authority and a reserve sharing group and states
that the Commission should require the ERO to clarify this issue when
modifying the Reliability Standard.
ii. Commission Determination
320. The Commission approves BAL-002-0. With regard to Xcel's
concern, the NERC glossary defines a reserve sharing group as ``two or
more balancing authorities that collectively maintain, allocate, and
supply operating reserves required for each balancing authority's use
in recovering from contingencies within the group.'' \149\ The
Commission notes that the Reliability Standard's Requirements and
Levels of Non-Compliance are applicable to both balancing authorities
and reserve sharing groups and are clear as to the roles and
responsibilities of these entities. The ERO will be responsible for
ensuring compliance with this Reliability Standard for all applicable
entities. A reserve sharing group, however, as an independent
organization, is able to determine on its own as a commercial matter
whether any penalties related to non-compliance should be re-
apportioned among the members of the group. With regard to Xcel's
concern about which entity calculates ACE, it is not clear from Xcel's
comments what it believes needs clarification. In general, we
understand that all balancing authorities are required to calculate ACE
with the exception of balancing authorities that use dynamic schedules
to provide all regulating reserves from another balancing authority. As
such, reserve sharing groups will not calculate ACE; they will rely on
balancing authorities to do so.
---------------------------------------------------------------------------
\149\ NERC Glossary at 15.
---------------------------------------------------------------------------
321. The Commission adopts the NOPR's proposal to require the ERO
to develop a modification to the Reliability Standard that refers to
the ERO rather than to the NERC Operating Committee in Requirements
R4.2 and R6.2. The ERO has the responsibility to assure the reliability
of the Bulk-Power System and should be the entity that modifies the
Disturbance Recovery Period as necessary. As identified in the
Applicability Issues section, the Commission directs the ERO to modify
this Reliability Standard to substitute Regional Entity for regional
reliability organization as the compliance monitor.\150\ The remaining
modifications to this Reliability Standard proposed in the NOPR are
discussed below.
---------------------------------------------------------------------------
\150\ See Applicability Issues: Regional Reliability
Organizations, supra section II.C.5. This directive applies
generically to all Reliability Standards that identify the regional
reliability organization as the compliance monitor.
---------------------------------------------------------------------------
iii. Including Demand-Side Management as a Resource
(a) Comments
322. SMA supports the Commission's proposed requirement explicitly
allowing demand-side response as a resource and agrees with the
Commission that DSM and direct load control should be considered on the
same basis as conventional generation or any other technology with
respect to contingency reserves. SMA states that nationwide its members
provide over 1,300 MW of demand that is curtailable on 10 minutes
notice or less and indicates that most of this curtailable capacity is
committed to utilities pursuant to retail tariffs or contracts for
operating reserves.
323. FirstEnergy states that demand-side resources should be
included as another tool for the balancing authority to use in meeting
the control performance and disturbance control standards. According to
FirstEnergy, demand-side resources should mimic the requirements of
generation resources but with a decrease in load rather than an
increase in generation response.
324. Process Electricity Committee generally supports the proposal
to treat demand response resources in a manner similar to conventional
generation so long as such demand resources participate in such DSM
programs voluntarily and comply with all applicable Reliability
Standards and requirements. Process Electricity Committee recommends
that the Commission modify its proposal to clarify that any such demand
response resources may be used only with the end-user's express written
agreement pursuant to clear contractual rights and obligations.
325. NY Major Consumers states that many large end use customers
currently have the ability to provide all ancillary
[[Page 16452]]
services, or are capable of providing these services in the near future
and that this capability has been recognized by Commission staff in
Docket No. AD06-2-000, Assessment of Demand Response Resources. NY
Major Consumers further states that there remains some ambiguity in the
proposed Reliability Standards as to the eligibility of technically-
qualified loads to provide these services and requests that the
Commission eliminate any such uncertainty and amend the proposed
Reliability Standards as further described in its comments.
326. Some commenters \151\ disagree with the Commission's proposal
to add a requirement explicitly allowing DSM as a resource for
contingency reserves. NERC, APPA and ISO-NE state that this requirement
is too prescriptive. NERC maintains that explicitly allowing DSM goes
well beyond the bounds of current utility practice and suggests an
improved directive would simply place DSM on the same basis as other
resources. APPA states that DSM resources should be included as an
option for a balancing authority to use in meeting its reserve
obligations, but that the Commission should not require NERC to modify
the Reliability Standard to explicitly identify DSM or any other type
of capacity as a resource for meeting reserve contingencies.
---------------------------------------------------------------------------
\151\ See NERC, ISO-NE, APPA and SDG&E.
---------------------------------------------------------------------------
327. In addition, ISO-NE states that DSM, to which it has access,
responds to capacity requirements and may not provide relief on a
contingency basis, but states that it has a limited number of resources
that could meet this requirement. SDG&E argues that DSM participation
in real-time is often unknown in comparison to conventional generation
and further states that the NOPR does not explain how DSM could be used
in real-time dispatch. Further, SDG&E maintains that the Commission has
not established a clear and workable definition of DSM.
328. MISO states that it is not clear about the meaning and
questions the value of the Commission's proposed requirement to include
DSM as a contingency reserve resource.\152\
---------------------------------------------------------------------------
\152\ MISO-PJM comments jointly with respect to IRO-006-3 only.
---------------------------------------------------------------------------
329. While EEI and MRO do not disagree with the Commission's
proposed requirement to include DSM, EEI states that both generation
and controllable load should comply with the same requirements to the
maximum extent possible, while MRO suggests that this requirement
should also include study and testing requirements.
(b) Commission Determination
330. We direct the ERO to submit a modification to BAL-002-0 that
includes a Requirement that explicitly provides that DSM may be used as
a resource for contingency reserves, subject to the clarifications
provided below.
331. The Commission disagrees with APPA that we should not
explicitly identify any type of capacity as a resource for meeting
reserve contingencies. The Commission believes that listing the types
of resources that can be used to meet contingency reserves makes the
Reliability Standard clearer, provides users, owners and operators of
the Bulk-Power System a set of options to meet contingency reserves,
and treats DSM on a comparable basis with other resources.
332. Many commenters argue that the Commission's proposed directive
that would explicitly allow DSM as a resource for contingency reserves
is too prescriptive. Concerns in this area generally fall into three
categories: (1) that DSM should be treated on a comparable basis as
other resources; (2) that the Reliability Standard should be based on
meeting an objective as opposed to stating how that objective is met
and (3) that DSM may not be technically capable of providing this
service.
333. With regard to the first concern, the Commission clarifies
that the purpose of the proposed directive is to ensure comparable
treatment of DSM with conventional generation or any other technology
and to allow DSM to be considered as a resource for contingency
reserves on this basis without requiring the use of any particular
contingency reserve option.\153\ The proposed directive as written
achieves that goal. With regard to the second concern, we believe that
this Reliability Standard is objective-based and we reiterate that we
are simply attempting to make it inclusive of other technologies that
may be able to provide contingency reserves, and are not directing the
use of any particular type of resource. By specifying DSM as a
potential resource for contingency reserves, the Commission is
clarifying the substance of the Reliability Standard.\154\
---------------------------------------------------------------------------
\153\ NOPR at P 157.
\154\ Order No. 672 at P 260.
---------------------------------------------------------------------------
334. With regard to commenters' concern that DSM may not be
technically possible, we first clarify that in order for DSM to
participate, it must be technically capable of providing contingency
reserve service. We expect that the ERO would determine what technical
requirements DSM would need to meet to provide contingency
reserves.\155\ While ISO-NE, APPA and SDG&E suggest that there is
limited access to qualified DSM or that DSM may not be optimal from a
technical standpoint, we note that SMA's comments state that its
members are currently providing over 1,300 MW of contingency reserve
service through retail tariffs or contracts. Alcoa states that it could
use the digital controls of its aluminum smelters to provide load
control that would be superior to conventional generation in terms of
ramp rate and speed of response. Also, the Commission notes that New
Zealand is currently using DSM for contingency reserves.\156\
Nonetheless, our requirement is that BAL-002-0 explicitly provides that
demand resources may be used as a resource for contingency reserves
without requiring the use of a specific resource or type of resource.
---------------------------------------------------------------------------
\155\ Id. (``We leave it to the ERO to develop proposed
Reliability Standards that appropriately balance reliability
principles and implementation features.'')
\156\ See http://www.electricitycommission.govt.nz/pdfs/rulesandregs/rules/rulespdf/Part-C-sched-C5-1Dec06.pdf
.
---------------------------------------------------------------------------
335. Accordingly, the Commission directs the ERO to explicitly
allow DSM as a resource for contingency reserves, and clarifies that
DSM should be treated on a comparable basis and must meet similar
technical requirements as other resources providing this service.\157\
---------------------------------------------------------------------------
\157\ ERCOT presently uses ``Load Acting as a Resource'' as part
of its reserves which are triggered at a specified frequency. This
is similar to but not the same as generation and is an example of
how load can perform as a resource.
---------------------------------------------------------------------------
iv. Continent-Wide Contingency Reserve Policy
(a) Comments
336. The Commission proposed in the NOPR to direct the ERO to
develop one uniform continent-wide contingency reserves policy.
Specifically, the Commission noted that the appropriate mix of
operating reserves, spinning reserves and non-spinning reserves should
be addressed on a consistent basis and consideration should be given to
the amount of frequency response from generation or load needed to
assure reliability. The Commission proposed that this policy be neutral
as to the source of the contingency reserves in terms of ownership or
technology.
337. SMA supports the Commission's proposal to develop a continent-
wide contingency reserve policy and agrees with the Commission that the
policy should be neutral as to the source of the
[[Page 16453]]
contingency reserves in terms of ownership or technology. EEI and
FirstEnergy both support development of a continent-wide contingency
reserve policy but suggest the need for regional variations across the
Bulk-Power System. For instance, FirstEnergy suggests that a one
percent peak load spinning requirement in the Eastern Interconnection
could be the equivalent of a two percent spinning requirement in the
Western Interconnection.
338. Other commenters \158\ disagree with the Commission's proposal
to have NERC develop a continent-wide contingency reserve policy and
instead support an Interconnection-wide or regional approach. APPA,
LPPC and MISO state that a continent-wide policy would not work because
of regional differences such as size, topology, mix of resources and
likely contingencies. While APPA supports the Commission's proposal
that contingency reserves should be based on the reliability risk of a
balancing authority not meeting load, it favors an Interconnection-wide
approach. MISO suggests that defining certain terms such as
``spinning,'' ``non-spinning,'' ``contingency'' and ``replacement'' and
having common calculations would be of value. It contends, however,
that EPAct does not apply to resource adequacy requirements, implying
that the Commission therefore is prevented from directing the
development of a continent-wide contingency reserve policy.
International Transmission shares this view.
---------------------------------------------------------------------------
\158\ See APPA, International Transmission, MISO-PJM, LPPC and
California PUC.
---------------------------------------------------------------------------
339. California PUC states that some customers can tolerate a
limited number of outages and suggests that it may be more cost-
effective to provide back-up power to customers with high reliability
needs rather than designing the entire system to a very high and
expensive level. California PUC disagrees with the Commission that
contingency reserves should be based only on the reliability risk of a
balancing authority not meeting load. It suggests that certain other
relevant factors should be considered, such as the number of customers
or MW lost, the value that customers in a certain area place on
reliability and the costs of avoiding outages (the cost of reserves).
(b) Commission Determination
340. We direct the ERO to submit a modification to BAL-002-0 to
include a continent-wide contingency reserve policy. We are not
prescribing the details of that policy. As the Commission stated in the
NOPR, ``[w]hile 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.'' \159\ In addition, the contingency
reserves should include sufficient frequency responsive resources such
that the net frequency response of the balancing authority is
sufficient for either interconnected or isolated operation.\160\
---------------------------------------------------------------------------
\159\ NOPR at P 156.
---------------------------------------------------------------------------
341. The Commission agrees with MISO that certain terms such as
``spinning'' and ``non-spinning'' or any other term used to describe
contingency or operating reserves could be developed continent-wide.
Additionally, we believe the technical requirements for resources that
provide contingency reserves should not change from region to region.
---------------------------------------------------------------------------
\160\ 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 have adequate
frequency response to assure recovery immediately following an
incident.
---------------------------------------------------------------------------
342. We believe a continent-wide contingency reserves policy would
assure that there are adequate magnitude and frequency responsive
contingency reserves in each balancing authority. This will improve
performance so that no balancing authority will be doing less than its
fair share.
343. With regard to California PUC's concerns regarding the cost of
providing reserves, and the suggestion that loss of firm load may be an
acceptable alternative to enhanced reliability of the system, the
Commission disagrees. Loss of firm load should not be permitted in
planning the system for a single contingency. However, the Commission
recognizes the appropriate concern of California PUC regarding costs.
The California PUC can have a strong role in this area by encouraging
or requiring DSM programs that can reduce the demand on the
transmission system.
344. With regard to statements that EPAct does not apply to
resource adequacy, we note that this Reliability Standard does not
concern resource adequacy, but addresses contingency reserves, which
are operating and not planning reserves. Operating reserves are not the
same as resource adequacy, a planning element. Section 215 authorizes
the Commission to approve Reliability Standards for contingency
reserves because they are necessary for real-time Reliable Operation of
the Bulk-Power System.
345. Accordingly, the Commission requires the ERO to develop a
continent-wide contingency reserve policy through the Reliability
Standards development process, which should include uniform elements
such as certain definitions and requirements as discussed in this
section. The Commission clarifies that the continent-wide policy can
allow for regional differences pursuant to Order No. 672, but that the
policy should include procedures to determine the appropriate mix of
operating reserves, spinning and non-spinning, as well as requirements
pertaining to the specific amounts of operating reserves based on the
load characteristics and magnitude, topology, and mix of resources
available in the region.
v. Disturbance Control Standard and the Associated Reserve Requirement
(a) Comments
346. The Commission identified two items in the Disturbance Control
Standard section of the NOPR. In the first item, the Commission agreed
with the interpretation that the 15 minute limit on a reportable
disturbance was ``absolute, objective, and measurable'' and therefore
enforceable in the present Reliability Standard. The second item
resulted in a proposal to modify Requirement R3.1, which currently
requires that a balancing authority to carry at least enough
contingency reserves to cover ``the most severe single contingency.''
The Commission proposed to change the Requirement to include enough
contingency reserves to cover any event or single contingency,
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. The Commission noted that this approach
would address staff's concern with Requirement R3.1--specifically,
addressing the ambiguity over whether the Requirement meant the loss of
generation or the loss of supply resulting from a transmission or
generation contingency.\161\
---------------------------------------------------------------------------
\161\ NOPR at P 153.
---------------------------------------------------------------------------
347. Most commenters \162\ express concern over the Commission's
proposal to add a Requirement that measures response for any event or
contingency that causes a frequency deviation. NERC states that this
proposed directive is overly prescriptive and suggests that an improved
modification would be to direct the ERO to resolve the ambiguity
[[Page 16454]]
in Requirement R3.1 as pointed out in the Staff Preliminary Assessment.
APPA suggests that the Commission should not require NERC to modify the
Reliability Standard, but should allow NERC to address the Commission's
concerns in its Reliability Standards development process and, while
doing so, NERC should consider defining ``Most Severe Single
Contingency'' contained in the WECC Frequency Response Standard White
Paper.\163\ Xcel has concerns about the compliance aspects of this
proposed modification stating that there is no equitable method to
assess an individual entity's performance for an occurrence that is
potentially Interconnection-wide.
---------------------------------------------------------------------------
\162\ See NERC, APPA, Xcel, MRO, ISO-NE, EEI and Nevada
Companies.
\163\ See NOPR at n.116.
---------------------------------------------------------------------------
348. NRC notes the NERC and Commission observations regarding the
declining trend in frequency response and states that this Reliability
Standard provides the opportunity to establish a frequency response
performance standard. NRC staff suggests that a Measure be added to
establish a frequency response.
349. MRO suggests that, if this requirement is adopted, a clear
definition of the event that causes a frequency deviation will be
required. ISO-NE comments that Requirement R3.1 is already clear and
the suggested modification is not clear because: (1) It is not possible
to plan for all such events and (2) it is not clear what is a
``significant deviation.'' EEI states that a requirement to measure
frequency response for any event or contingency could provide
beneficial information for system operators but states that there is
presently no requirement for generators to report all outages so
measurements cannot be made. EEI further states that the compliance
costs of this requirement may outweigh the benefits. The Nevada
Companies disagree with the proposed modification and state that the
Reliability Standard must instead focus strictly on the loss of supply.
The Nevada Companies further state that, for purposes of this
Reliability Standard, WECC's present contingency reserve criterion,
which requires consideration of loss of generation that would result
from the most severe single contingency, is most applicable.
350. Georgia Operators comment that the Commission's intent in this
proposed modification should not be interpreted to require a balancing
authority to carry enough reserves to cover any event resulting in a
significant deviation in frequency and should not be read to suggest
that frequency rather than ACE should be used to measure a balancing
authority's deployment of reserves for contingencies.
351. MISO and ERCOT comment on the Commission's suggestion that
NERC should consider defining a frequency deviation of 20 milli Hertz
lasting longer than the 15 minute recovery period as a significant
deviation. MISO argues that the value could vary in different
Interconnections and believes the current method is acceptable. ERCOT
states that it is not feasible to apply a single frequency-deviation
number to ERCOT and the other Interconnections and asks the Commission
to instead consider a Reliability Standard that is proportional to the
size of each Interconnection. ERCOT notes that 20 milli Hertz would be
far more strict than ERCOT's historic frequency performance.
(b) Commission Determination
352. On this issue, the Commission will not direct the ERO to
modify BAL-002-0 in the manner proposed in the NOPR. Rather, the
Commission directs the ERO to address the concerns expressed by the
Commission about having enough contingency reserves to respond to an
event on the system in Requirement R3.1 and how such reserves are
measured. The ERO should address this through adoption or modification
of Requirements and metrics in the Reliability Standards development
process.
353. NERC correctly points out that the Commission's proposal on
this point stemmed from the ambiguity in Requirement R3.1 that
Commission staff highlighted in the Staff Preliminary Assessment.
Requirement R3.1 currently requires that a balancing authority carry at
least enough contingency reserves to cover ``the most severe single
contingency.'' The Commission emphasizes that the goal of this
Reliability Standard is to insure against the reliability risk of not
serving load by matching generation and load following any disturbance
or event that results in a significant deviation in frequency.
Consistent with this goal, the Commission believes that this
Reliability Standard should be inclusive of all events, i.e., loss of
supply, loss of load or significant scheduling problems, which can
cause frequency disturbances and should address how balancing
authorities should respond. The Commission notes that PJM recently
issued a paper addressing frequency excursion related to scheduling
problems.\164\
---------------------------------------------------------------------------
\164\ Id. at n.134.
---------------------------------------------------------------------------
354. In the NOPR, the Commission identified two concerns in the
Disturbance Control Standard section of BAL-002-0. The first discussed
NERC's comment that the Reliability Standard is ``absolute, objective,
and measurable'' because it allows up to 15 minutes for the recovery
from a reportable disturbance,\165\ and second, the Commission asked
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.\166\ No commenters address the first concern
but many commented on the second.
---------------------------------------------------------------------------
\165\ NERC Comments on the Staff Preliminary Assessment at 41.
\166\ NOPR at P 153.
---------------------------------------------------------------------------
355. First, the Commission directs the ERO to develop a
modification to the Reliability Standard requiring that any single
reportable disturbance that has a recovery time of 15 minutes or longer
be reported as a violation of the Disturbance Control Standard. This is
consistent with our position in the NOPR and NERC's position in
response to the Staff Preliminary Assessment of the Requirements in
BAL-002-0, and was not disputed or commented upon by any NOPR
commenters.
356. Taking into account commenters' concerns about defining a
significant deviation as a frequency deviation of 20 milli Hertz
lasting longer than the 15 minute recovery period, the Commission will
not direct a specific change. Instead, we direct the ERO, through the
Reliability Standards development process, to modify this Reliability
Standard to define a significant deviation and a reportable event,
taking into account all events that have an impact on frequency, e.g.,
loss of supply, loss of load and significant scheduling problems, which
can cause frequency disturbances and to address how balancing
authorities should respond. As suggested by NRC, this or a related
Reliability Standard should also include a frequency response
requirement. The present Control Performance Standards represent the
monthly and yearly averages which are appropriate for measuring long-
term trends but may not be appropriate for measuring short-term events.
In addition, the measures should be available to the balancing
authorities to assist in real-time operations.\167\
---------------------------------------------------------------------------
\167\ It is the Commission's understanding that the Balancing
Authority ACE Limit Standards that are currently being field tested
are triggered on frequency deviations and can be used as feedback to
the real-time operations personnel.
---------------------------------------------------------------------------
vi. Summary of Commission Determination
357. The Commission approves Reliability Standard BAL-002-0 as
[[Page 16455]]
mandatory and enforceable. In addition, the Commission directs the ERO
to develop a modification to BAL-002-0 through the Reliability
Standards development process that: (1) Includes a Requirement that
explicitly provides that DSM may be used as a resource for contingency
reserves; (2) develops a continent-wide contingency reserve
policy;\168\ and (3) refers to the ERO rather than the NERC Operating
Committee in Requirements R4.2 and R6.2. In addition, the Commission
directs the ERO to modify the Reliability Standard in a manner that
recognizes the loss of transmission as well as generation, thereby
providing a realistic simulation of possible events that might affect
the contingency reserves.
---------------------------------------------------------------------------
\168\ This could be accomplished by modifying Requirement R2 or
developing a new Reliability Standard.
---------------------------------------------------------------------------
d. Frequency Response and Bias (BAL-003-0)
358. The purpose of BAL-003-0 is to ensure that a balancing
authority's frequency bias setting \169\ is accurately calculated to
match its actual frequency response.\170\ In the NOPR, the Commission
proposed to approve Reliability Standard BAL-003-0 as mandatory and
enforceable. In addition, pursuant to section 215(d) of the FPA and
Sec. 39.5(f) of our regulations, the Commission proposed to direct
NERC to submit a modification to BAL-003-0 that: (1) Includes Levels of
Non-Compliance and (2) modifies Measure M1 to include yearly surveys of
frequency response.\171\
---------------------------------------------------------------------------
\169\ Frequency bias setting is a value expressed in MW/0.1 Hz,
set into a balancing authority ACE algorithm, which allows the
balancing authority to contribute its frequency response to the
Interconnection. See NERC glossary at 7.
\170\ The actual frequency response is the increase in output
from generators after the loss of a generator and determines the
frequency at which generation and load return to balance.
\171\ NOPR at P 177.
---------------------------------------------------------------------------
359. The Commission further requested comments on whether BAL-003-0
appropriately addresses frequency bias setting during normal as well as
emergency conditions and whether a requirement should 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.\172\
---------------------------------------------------------------------------
\172\ Id. at P 175.
---------------------------------------------------------------------------
i. Comments
360. Several commenters address the Commission's proposal to direct
the ERO to modify Measurement M1 to include yearly surveys.
361. LPPC agrees with the Commission's proposed directive. EEI
states that NERC currently conducts an annual frequency response
characteristic survey that appears to address the Commission's proposed
directive. If the yearly survey would replace the frequency response
characteristic survey, EEI states that the survey should include
questions regarding the scope of potential new requirements. ISO/RTO
Council believes that yearly surveys are unnecessary and would prefer
that NERC focus on surveying balancing authority responses to large
frequency disturbances.
362. APPA agrees that the Commission has correctly identified
shortcomings in this Reliability Standard and states that, while the
Commission may have identified appropriate modifications, the
determination should be left to NERC to address in the first instance.
APPA supports the development of a consistent Interconnection-wide
policy and suggests that NERC should consider procedures similar to
those used in ERCOT and WECC.
363. FirstEnergy suggests that Requirements R5 and R5.1 of this
Reliability Standard should be required in lieu of Requirement R2 if a
balancing authority has load but no generation (R5) or if a balancing
authority has generation but no load (R5.1). FirstEnergy states that
without this change the Reliability Standard is not clear because it
implies that a balancing authority could choose between two options.
Most commenters responded to the Commission's request for comments in
the NOPR by stating that additional requirements do not need to be
added for balancing authorities to calculate the frequency response
necessary for reliability in each of the Interconnections. NERC states
that frequency bias is currently over-compensated across the
Interconnections and that requiring frequency bias to be actual
frequency response may reduce control performance. Additionally, NERC
states that some studies have shown a decline in frequency (e.g.,
governor) response over several decades and that it is addressing this
issue through the request for a new Reliability Standard on frequency
response. NERC also notes that BAL-003-0 will be replaced soon by the
new balancing Reliability Standards that are approaching ballot.
364. In general, EEI believes that systemic over-biasing does not
present a reliability problem and the Commission should exercise
caution in requesting changes to this Reliability Standard. EEI states
that the frequency bias varies continuously in terms of the type and
magnitude of load changes, and the types and loading of generation
resources. Therefore, EEI suggests that the accuracy of any estimate of
frequency bias is highly questionable. Further, EEI states that the one
percent default value was deliberately set to over-bias the system to
ensure adequate frequency response. EEI is unaware of any evidence of
undamped oscillations due to this over-biasing and states that the one
percent floor should be recognized by the Commission as just and
reasonable until an optimum frequency bias value can be studied. EEI
sees the potential need for developing requirements for modifying
frequency bias during emergency conditions, citing evidence from the
August 2003 blackout suggesting that oscillations following the ISO New
England separation from the Eastern Interconnection may have been
caused by over-biasing.
365. ISO/RTO Council comments that the details of the procedures
that are used to ensure frequency bias are appropriate and no
additional requirements for balancing authorities are needed. It
disagrees with the Commission's proposal to develop uniform
requirements for frequency bias.\173\ ISO/RTO Council states that there
is no single right way to develop and apply a frequency bias setting
and no universally accepted norm. ISO/RTO Council believes the key
point is that the frequency bias setting be greater than the natural
frequency response of the system and believes that the percent minimum
currently in place is sufficient. ISO/RTO Council recommends that NERC
investigate (1) reliability issues associated with low natural
response; (2) causes of decreasing natural response and (3) possible
opportunities for creating markets for load and generator response to
frequency changes.
---------------------------------------------------------------------------
\173\ See id. at P 129.
---------------------------------------------------------------------------
366. Xcel responds that there is no need for this Reliability
Standard to address frequency bias during black start, restoration and
islanding due to the transitional nature of those events. Northern
Indiana opposes imposing greater restrictions on frequency bias and
frequency response calculations, stating that they could be counter-
productive by making procedural errors more likely, which could harm
reliability. Northern Indiana suggests that the approach suggested in
the NOPR would require frequency
[[Page 16456]]
response to be calculated based on various contingencies in a way that,
if a particular contingency does not occur, the balancing authority
might contribute to an incorrect frequency response. Northern Indiana
maintains that the existing Reliability Standard is appropriate because
it reflects the unique characteristics of each utility's operating
characteristics and allows experienced, certified operators to act to
avoid adverse effects on the electric system.
367. MidAmerican believes that a requirement for balancing
authorities to calculate the necessary frequency response is not
necessary for reliability, nor should balancing authorities be required
to identify the method to obtain that frequency response. MidAmerican
states that the bias settings addressed in BAL-003-0 are appropriate
for normal and emergency conditions. It further explains that large
disturbances resulting in large frequency shifts can only be corrected
by bringing load and generation into balance. MidAmerican further
states that the annual review of bias settings uses tie line and
frequency deviations during large disturbances to provide bias settings
representative of relatively large frequency excursions and adds that
these settings, along with automatic generation control and governor
response, provide an over-biased response to steady-state frequency
deviations. MidAmerican states that as long as system disturbances are
continually tracked to ensure frequency decay is sufficiently
mitigated, enough frequency bias will be on the system and the current
Reliability Standard can be considered sufficient.
368. MISO states that it expects the Commission's concerns with the
frequency response and bias standard to be addressed in NERC's
frequency response Reliability Standard Authorization Request.
ii. Commission Determination
369. The Commission approves Reliability Standard BAL-003-0 as
mandatory and enforceable. In addition, the Commission directs the ERO
to develop a modification to BAL-003-0 as discussed below.
370. With respect to the frequency of frequency response surveys,
EEI states that NERC currently conducts an annual frequency response
characteristic survey that appears to address the Commission's concern.
The Commission disagrees. The surveys that were performed on a yearly
basis are not available on NERC's Web site and the ISO/RTO Council
believes that more frequent analysis after large frequency disturbances
is appropriate. The Commission understands that the last analysis was
performed in 2002. Currently, Measure M1 only requires balancing
authorities to perform surveys when requested by the NERC operating
committee. As identified in Order No. 672, the Reliability Standards
should be based on actual data.\174\ Therefore, on further
consideration, instead of requiring yearly surveys as proposed in the
NOPR, the Commission believes that the frequency of these surveys
should be based on the data requirements that will assist the ERO to
determine if the balancing authorities are providing adequate and
equitable frequency response to disturbances on the Bulk-Power System.
Accordingly, we direct the ERO to determine the optimal periodicity of
frequency response surveys necessary to ensure that Requirement R2 and
other Requirements of the Reliability Standard are being met and to
modify Measure M1 based on this determination.\175\
---------------------------------------------------------------------------
\174\ Order No. 672 at P 324.
\175\ As input to the Reliability Standards development process,
the Commission suggests that the ERO perform sufficient analysis to
understand how the frequency response varies between balancing
authorities and Interconnections.
---------------------------------------------------------------------------
371. With respect to FirstEnergy's comment, Requirement R2 states
that the frequency bias setting should be as close as practical to, or
greater than, the balancing authority's frequency response. That is the
Requirement concerning the relationship between frequency response and
frequency bias, with Requirement R5 and R5.1 providing minimum
frequency bias values for specific types of balancing authorities. The
three Requirements do not conflict. A balancing authority must use a
frequency bias of at least one percent and they must have a frequency
bias that is as close as practical to, or greater than, the balancing
authority's actual frequency response. As will be discussed more fully
below, the Commission expects each balancing authority to meet these
Requirements to be in compliance with the existing BAL-003-0.
372. With respect to the Commission's request for comments, most
commenters are opposed to additional requirements for balancing
authorities to calculate the frequency response necessary for
reliability in each of the Interconnections. NERC states that frequency
bias is currently over-compensated across the Interconnections, while
EEI states that the one percent default value was deliberately set to
over-bias the system to ensure adequate Frequency Response. The ISO/RTO
Council comments that frequency bias settings are appropriate and all
agree that no additional requirements are needed. However, NERC
acknowledges that the frequency response of the Eastern and Western
Interconnection is decreasing and states it will address the issue with
a new frequency response Reliability Standard. There is no similar need
in ERCOT because ERCOT has adopted an approach to calculate the
necessary frequency response needed for Reliable Operation and has
identified a method of obtaining the necessary frequency response as
discussed in BAL-001-0 regional difference. The Commission understands
that this approach was based on lessons learned from the May 15, 2003
event \176\ that resulted in larger than anticipated amounts of firm
load shedding by underfrequency relays operation due to less than
desirable amounts of frequency response.
---------------------------------------------------------------------------
\176\ See Underfrequency Load Shedding 2006 Assessment and
Review by ERCOT Dynamics Working Group, available at http://www.ercot.com/meetings/ros/keydocs/2007/0111/10a._DWG_2006_UFLS_Assessment_12-18-06.doc
.
---------------------------------------------------------------------------
373. The Commission is not persuaded by the commenters. We conclude
that the minimum frequency response needed for Reliable Operation
should be defined and methods of obtaining the frequency response
identified. In addition to the ERCOT experience, EEI provides an
additional example that underscores the Commission's concern in this
area with its discussion of the ISO-NE frequency oscillations resulting
from the August 14, 2003 blackout. Severe oscillations were observed in
the ISO-NE frequency when it separated from the Eastern Interconnection
during the August 14, 2003 blackout.\177\ The ISO-NE operators acted
quickly to reduce the bias setting so as to eliminate the self-induced
frequency oscillations before they affected system reliability. This
apparent mismatch between the bias and the actual frequency response
might have caused the ISO-NE system to cascade if it had not been for
the quick actions of its operators. Therefore, we direct the ERO to
either modify this Reliability Standard or develop a new Reliability
Standard that defines the necessary amount of frequency response needed
for Reliable Operation and methods of obtaining and measuring that
frequency response is available.
---------------------------------------------------------------------------
\177\ See Performance of the New England and Maritimes Power
Systems During the August 14, 2003 Blackout by Independent System
Operator New England, available at https://www.npcc.org/publicFiles/blackout/archives/Restoration_of_the_NPCC_Areas.pdf
.
---------------------------------------------------------------------------
374. As the Commission noted in the NOPR and in our response to
FirstEnergy, Requirement R2 of this
[[Page 16457]]
Reliability Standard states that ``[e]ach Balancing Authority shall
establish and maintain a Frequency Bias Setting that is as close as
practical to, or greater than, the Balancing Authority's Frequency
Response.'' The Commission believes that the achievement of this
Requirement is fundamental to the tie line bias control schemes that
have been in use to assist in balancing generation and load in the
Interconnections for many years.\178\ We understand that the present
Reliability Standard sets the required frequency response of the
balancing authorities to be approximately one percent or greater by
requiring that the frequency bias shall not be less than one percent
and that the frequency bias be as close as practical to, or greater
than, the actual frequency response.
---------------------------------------------------------------------------
\178\ Cohn, Nathan, Control of Generation and Power Flow on
Interconnected Systems, (John Wiley and Sons 1966).
---------------------------------------------------------------------------
375. While EEI supports additional requirements related to
frequency bias during emergency conditions, Xcel states that frequency
response during black start, restoration and islanding situations need
not be addressed in a Reliability Standard due to the transient nature
of these events. The Commission disagrees with Xcel and agrees with
EEI. The Bulk-Power System should be operated in a reliable manner at
all times.
376. Accordingly, the Commission approves Reliability Standard BAL-
003-0 as mandatory and enforceable. In addition, the Commission directs
the ERO to develop a modification to BAL-003-0 through the Reliability
Standards development process that: (1) Includes Levels of Non-
Compliance; (2) determines the appropriate periodicity of frequency
response surveys necessary to ensure that Requirement R2 and other
requirements of the Reliability Standard are being met, and to modify
Measure M1 based on that determination and (3) defines the necessary
amount of Frequency Response needed for Reliable Operation for each
balancing authority with methods of obtaining and measuring that the
frequency response is achieved.
e. Time Error Correction (BAL-004-0)
377. 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.\179\ In the NOPR, the
Commission proposed 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
proposed to direct that NERC submit a modification to BAL-004-0 that
includes Levels of Non-Compliance and additional Measures.\180\
---------------------------------------------------------------------------
\179\ 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 18. Time error is caused by the accumulation of
frequency error over a given period.
\180\ NOPR at P 184.
---------------------------------------------------------------------------
378. Further, the Commission noted that WECC has implemented an
automatic time error correction procedure \181\ that, according to data
on the NERC Web site, is more effective in minimizing both time error
corrections and inadvertent interchange.\182\ The NOPR asked for
comment on whether the Commission should require NERC to adopt
Requirements similar to those in the WECC automatic time error
correction procedure.
---------------------------------------------------------------------------
\181\ See http://www.wecc.biz/documents/library/procedures/Time_Error_
Procedure--10-04-02.pdf.
\182\ See http://www.nerc.com/~filez/inadv.html (regarding inadvertent interchange data) and http://www.nerc.com/~filez/
timerror.html (regarding time error correction).
---------------------------------------------------------------------------
i. Comments
379. MISO states that it is unclear what the Commission had in mind
with its proposed directive to include Levels of Non-Compliance and
additional Measures and that the reliability benefit of such Levels of
Non-Compliance and additional Measures is also unclear.
380. While APPA and EEI favor adopting the WECC approach to time
error correction, NERC and the majority of other commenters \183\ are
either opposed to adopting the WECC automatic time error correction
procedure in other regions or think time error correction is more
appropriately addressed as a business practice. NERC notes that the
WECC procedure is in lieu of an equivalent procedure contained within
the business practices of the North American Energy Standards Board
(NAESB) and suggests that instructions for implementing a time error
correction are more appropriately addressed as a business practice.
Northern Indiana maintains that WECC-type procedures are unnecessary,
and could result in unintended process errors or operational problems.
It urges the Commission to allow time error issues to remain within the
jurisdiction of NAESB and suggests that time error correction is not
essential to reliability and is more appropriately treated as a non-
essential guide. ISO-NE agrees that time error correction is not a
reliability issue.
---------------------------------------------------------------------------
\183\ See Xcel, Northern Indiana, ISO-NE, LPPC and MISO-PJM.
---------------------------------------------------------------------------
381. Xcel states that its operating company located in WECC has
experienced problems with WECC's automatic time error correction
procedure and therefore does not support adoption of this procedure by
other regions. In addition, Xcel states that time error correction is
not necessary for utilities in regional markets where imbalances are
settled financially and the regional market operator manages the
scheduled interchange offsets. LPPC suggests that there is not enough
evidence to show that WECC's time error correction procedure is
appropriate for the Eastern Interconnection. LPPC adds that the choice
of switching to the WECC procedure should be left up to the NERC
Reliability Standards development process.
382. MISO states that, while the WECC procedure has advantages with
regard to reducing inadvertent interchange values, it does not reduce
the number of time error corrections because WECC monitors and performs
time error correction on a shorter time frame than the Eastern
Interconnection. MISO argues that this is more of a technical
requirement and not a Reliability Standard and suggests there are
simpler ways to control time error and manage inadvertent balances.
MISO states that NERC previously allowed unilateral payback of
inadvertent balance of up to 20 percent of bias when the payback is in
a direction to reduce time error and states that this reduced the
number of time error corrections while giving balancing authorities a
tool to balance their accounts. In its comments addressing BAL-006-1,
MISO suggests that the number of time error corrections could be
reduced by following the European methodology which has a wider window
of allowable time and implements full clock-day, but with a smaller
offset.
ii. Commission Determination
383. The Commission approves 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 directs
the ERO to develop a modification to BAL-004-0 through the Reliability
Standards development process that includes Levels of Non-Compliance
and additional Measures for Requirement R3. Further, based on
commenters' concerns that there is no engineering basis for changing
the time error correction to the WECC approach or any other approach,
when reviewing the Reliability Standard during the ERO's scheduled
five-year cycle of review, we direct the ERO to perform
[[Page 16458]]
research that would provide a technical basis for the present approach
or for any alternative approach.
384. Many commenters aver that the time error correction procedure
belongs within the realm of NAESB and is not a reliability issue. The
Commission disagrees, as BAL-004-0 is intended to ensure that time
error corrections are performed in a manner that does not adversely
affect the reliability of the Interconnection. The financial aspects of
time error correction such as MISO's concern about the unilateral
payback of interchange imbalances remain with NAESB. However, the
technical details, including the means to carry out the procedure, are
a reliability issue.
385. We believe that the efficiency of the time error correction
can be viewed as a measure of whether all balancing authorities are
participating in time error correction. Requirement R3 states that each
balancing authority, when requested, shall participate in a time error
correction. The Commission believes that this is a critical
requirement, but the data on the NERC Web site indicates that
efficiency is decreasing, indicating that fewer balancing authorities
are employing time error correction.\184\ Therefore, the Commission
affirms its preliminary finding that the efficiency of time error
corrections has decreased over the last ten years and that
participation in time error corrections may be lacking.\185\
Accordingly, we direct the ERO to develop additional Measures and add
Levels of Non-Compliance to assure that the requirements in Requirement
R3 are achieved. One approach to achieving this would be to use the
existing measurement of efficiency as a metric of participation of all
balancing authorities. If the efficiency is significantly less than 100
percent, the Measures should provide a process to identify which
balancing authorities are not meeting the requirements of the
Reliability Standard.
---------------------------------------------------------------------------
\184\ See W.R. Prince, et al., Cost Aspects of AGC, Inadvertent
Energy and Time Error, IEEE Transactions on Power Systems, February
1990, at 111.
\185\ NOPR at P 179, 183.
---------------------------------------------------------------------------
386. Although the Commission noted in the NOPR that WECC's time
error correction procedure appears to serve as a more effective means
of accomplishing time error correction, based on concerns that there is
no engineering basis for changing the time error correction to the WECC
approach, the Commission will not direct the ERO to adopt requirements
similar to WECC's procedure. With the exception of comments from APPA
and EEI, most commenters do not believe or are uncertain about whether
the WECC procedure is appropriate for the Eastern Interconnection.
However, when this Reliability Standard is scheduled for its regular
five-year cycle of review, the Commission directs the ERO to perform
whatever research it and the industry believe is necessary to provide a
sound technical basis for either continuing with the present practice
or identifying an alternative practice that is more effective and helps
reduce inadvertent interchange.
387. The Commission agrees with MISO regarding the number of time
error corrections using WECC's procedure. However, the magnitude of the
frequency change in the WECC automatic time error correction is smaller
than the manual correction and timing of the corrections are better
correlated to when the error was created. These two characteristics of
the WECC procedure avoid placing the system in less secure conditions
and tie the payback to the initiating action, both of which appear to
better serve both reliability and equity.
f. Automatic Generation Control (BAL-005-0)
388. The 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.
389. In the NOPR, the Commission proposed 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 proposed to direct NERC to 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 additional 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.\186\
---------------------------------------------------------------------------
\186\ NOPR at P 197.
---------------------------------------------------------------------------
390. Further, the NOPR stated that the Commission is interested in
knowing whether any balancing authority is experiencing or is
predicting any difficulty in obtaining sufficient automatic generation
control.
i. Minimum Amount of Regulating Reserves
(a) Comments
391. South Carolina E&G and SMA support the Commission's proposal
to include a requirement that addresses minimum regulating reserves. It
states that the control performance standard metric is a lagging
indicator of necessary reserves and other standards such as frequency
response may eventually provide a more dynamic real-time indicator.
South Carolina E&G believes the Commission's proposal provides a good
interim solution.
392. Alcoa comments that, in establishing a minimum amount of
reserves, NERC should be required to consider the quality of each
source of reserves. Alcoa suggests that digitally controlled DC loads,
such as an aluminum smelter, could respond much more rapidly and
accurately than thermal generators and that using such resources could
reduce the response time for recovery, allowing thermal units to carry
fewer spinning reserves and increasing operating efficiencies of the
grid.
393. NERC and other commenters \187\ suggest that the Commission's
proposed directive to have NERC include ``Requirements that identify
the minimum amount of automatic generation control or regulating
reserves a balancing authority must have at any given time'' is too
prescriptive. They also object to this proposed requirement since a
balancing authority's failure to maintain sufficient regulating
reserves will result in violations of control performance standard
criteria already found in BAL-001-0.
---------------------------------------------------------------------------
\187\ See APPA, EEI, International Transmission, MISO-PJM,
MidAmerican and LPPC.
---------------------------------------------------------------------------
394. NERC further states that a requirement to have a minimum
amount of regulating reserves would result in an arbitrary constraint
that would not add to reliability and suggests that the Commission
instead direct NERC to consider the issue of a minimum requirement in
its Reliability Standards process in order to determine the reliability
benefit.
395. EEI states that the industry currently has no consensus-based,
sound engineering methodology for determining a minimum regulating
reserve requirement given widely varying needs throughout the country.
[[Page 16459]]
Nonetheless, EEI offers several guidelines that it says could be used
to provide estimates for minimum regulating reserves. Similarly,
MidAmerican states that normal regulating margins can vary from one
balancing authority to another, and even within one balancing
authority, due to frequently changing load characteristics making it
extremely difficult to quantify an hourly required level of reserves.
MidAmerican suggests that instead of prescriptively quantifying reserve
levels, the ERO should continue to allow the industry to find efficient
ways to comply with the control performance standards of BAL-001-0.
396. FirstEnergy suggests that a single entity should have the
responsibility to establish, through an annual review process, the
level of regulating reserves that a balancing authority must maintain
pursuant to the control performance standard requirements. FirstEnergy
suggests that all generators and technically qualified DSM that
participate in energy markets should install automatic generation
control as a condition of market participation. In non-market areas,
FirstEnergy suggests that balancing authorities could meet requirements
through bilateral contracts or the normal scheduling process and
suggests that the Commission might have to assert its jurisdiction and
order technically qualified DSM providers to install automatic
generation control at their facilities. FirstEnergy states that further
work would need to be conducted on the technical qualifications and
capacity thresholds that would control whether installation of
automatic generation control would be required.
(b) Commission Determination
397. On this issue, the Commission directs the ERO to modify BAL-
005-0 through the Reliability Standards development process to develop
a process to calculate the minimum regulating reserve for a balancing
authority, taking into account expected load and generation variation
and transactions being ramped into or out of the balancing authority.
398. As a general matter, the Commission believes that a single
entity should establish the level of regulating reserve required based
on the generation mix and ramping rates in the region. We disagree with
commenters that minimum regulating reserve requirements are not
necessary. As South Carolina E&G correctly points out, the control
performance standard metric is a lagging indicator and, as such, does
not provide a good indication that the necessary amounts of regulating
reserve are being carried at all times. The Commission notes that
Requirement R2 requires maintenance of a level of regulating reserves
in order to prospectively meet the control performance standard but
does not provide a calculation for the exact level which would be
required. In particular, the Commission believes that, while the
control performance standard metric is useful in identifying trends
relating to poor regulating practices, specification of minimum reserve
requirements to be maintained at all times would complement the control
performance standard metrics by providing real-time requirements
necessary for proper control.
399. With regard to Alcoa's comment, the Commission agrees that the
quality of reserves is relevant in determining if the resource is able
to technically qualify as regulation.
400. Nevertheless, the Commission recognizes commenters' concerns
related to the calculation of minimum regulation. EEI has offered
several possible methods to calculate the minimum amount of regulation
needed for reliability, which may or may not be consistent with others
in the industry. The fundamental reason for regulating reserves is to
balance load and generation in the short term due to the random
variations in the balancing authorities' loads and to accommodate
ramping of transactions. The Commission therefore directs the ERO to
develop a process to calculate the minimum regulating reserve for a
balancing authority, taking into account expected load and generation
variation and transactions being ramped into or out of the balancing
authority.
ii. Title Change and Inclusion of DSM.
(a) Comments
401. As an initial matter, many commenters express confusion about
the Commission's proposal to require NERC to change the title of the
Reliability Standard to be neutral as to the source of the reserves,
and include DSM and direct control load management as part of
contingency reserves.\188\ In particular, these commenters argue that
this Reliability Standard pertains to regulating reserve and not
contingency reserves.
---------------------------------------------------------------------------
\188\ EEI, TVA, International Transmission, Multiple
Interveners, MISO-PJM, South Carolina E&G and Wisconsin Electric.
---------------------------------------------------------------------------
402. Constellation agrees with the Commission that DSM and direct
control load management should be included as viable options for
regulating reserves.\189\ MidAmerican agrees with the Commission on the
proposed title change to allow it to be neutral as to the source of
reserves but cautions the Commission on including DSM as a source of
contingency reserves. While MidAmerican believes it proper to include
direct control load management, which is under direct control of the
system operator in contingency reserves, it states that the term DSM
(as defined in the NERC glossary) is too general and includes programs
that cannot contribute toward contingency reserves.
---------------------------------------------------------------------------
\189\ Since the Commission used the term ``contingency
reserves'' inappropriately in this section, we assume that
Constellation intended this to be regulating reserves.
---------------------------------------------------------------------------
403. APPA and International Transmission both disagree with the
Commission's proposals to change the title of this Reliability Standard
and to include DSM and direct control load management. APPA suggests
that DSM and direct control load management are not operationally
equivalent to dispatchable generation resources and does not believe
these programs are an effective source of regulating reserve given the
current state of technology. International Transmission simply states
that regulating reserves required by BAL-005-0 are specifically
responsive to automatic generation control.
404. ISO-NE disagrees with the Commission's proposal to include DSM
and direct control load management as part of this service, stating
that responsive load has not demonstrated the load following capability
necessary to provide regulation and that it is not aware of any load-
based resources that can closely follow automatic generation control
signals sent every four seconds. As an alternative to the Commission's
approach, ISO-NE suggests that the Reliability Standard should define
the reliability purpose or objective and then be resource-neutral.
(b) Commission Determination
405. At the outset, the Commission agrees with commenters that this
Reliability Standard applies to regulating reserves and not contingency
reserves. The references to contingency reserves under this Reliability
Standard in the NOPR are confusing. The Commission clarifies that its
direction to the ERO in this section is for it to develop a
modification to BAL-005-0 through the Reliability Standards development
process that changes the title of the Reliability Standard to be
neutral as to the source of regulating reserves and allows the
inclusion of technically qualified DSM and direct
[[Page 16460]]
control load management as regulating reserves, subject to the
clarifications provided in this section.
406. We disagree that it is not possible to use DSM and direct
control load management as a source of regulating reserves or any other
type of operating reserves. The Commission notes that, while DSM and
direct control load management may not be widely used today as a source
of operating reserves, comments received and other evidence suggest
that certain types of loads are technically capable of providing this
service. For example, comments received from Alcoa suggest that certain
loads, such as digitally controlled DC loads, are capable of responding
much faster than generation to a reserve need.
407. Given that most of the commenters' concerns over the inclusion
of DSM as part of regulating reserves relate to the technical
requirements, the Commission clarifies that to qualify as regulating
reserves, these resources must be technically capable of providing the
service. In particular, all resources providing regulation must be
capable of automatically responding to real-time changes in load on an
equivalent basis to the response of generation equipped with automatic
generation control. From the examples provided above, the Commission
understands that it may be technically possible for DSM to meet
equivalent requirements as conventional generators and expects the
Reliability Standards development process to provide the qualifications
they must meet to participate. These qualifications will be reviewed by
the Commission when the revised Reliability Standard is submitted to
the Commission for approval.
iii. Whether Balancing Authorities Are Experiencing or Predicting
Difficulty in Obtaining Sufficient Automatic Generation Control
(a) Comments
408. Constellation states that its ability to obtain regulating
reserves is hampered by a lack of resources that qualify as regulation
and the practices that some transmission service providers have adopted
in implementing dynamic transfers needed to procure regulating reserves
from other balancing authorities. In particular, Constellation states
that many transmission service providers impose a requirement that
regulation services must be provided using firm transmission.
Constellation suggests that purchasing regulation from another
balancing authority using non-firm transmission service is allowed
under the Reliability Standards and that Requirement R5 of BAL-005-0
provides that balancing authorities must have back-up plans to provide
replacement regulation service if the purchased regulation service is
lost. Constellation requests that the Commission clarify that the
transmission providers may not impose a requirement to rely exclusively
on firm transmission for the dynamic transfers of regulating reserves.
(b) Commission Determination
409. In response to Constellation's concerns, the Commission notes
that, if regulation is being provided over non-firm transmission
service, the entity receiving the regulation should be responsible for
having a back-up plan to include loss of the non-firm transmission
service as referenced in Requirement R5. The Commission believes that a
balancing authority may use non-firm transmission service for procuring
regulation, so long as that balancing authority has a back-up plan that
it can implement to include loss of non-firm transmission service.
iv. Other Comments
(a) Comments
410. MISO states that it is uncertain of the basis of the claim
that there have been an increased number of ``[automatic generation
control] controllable'' frequency excursions.\190\ MISO further states
that data in the Eastern Interconnection shows the number of larger-
slower excursions has decreased over the past few years.
---------------------------------------------------------------------------
\190\ NOPR at P 194.
---------------------------------------------------------------------------
411. Xcel requests that the Commission reconsider Requirement R17
of this Reliability Standard stating that the accuracy ratings for
older equipment (current and potential transformers) may be difficult
to determine and may require the costly replacement of this older
equipment on combustion turbines and older units while adding little
benefit to reliability. Xcel states that the Commission should clarify
that Requirement R17 need only apply to interchange metering of the
balancing area in those cases where errors in generating metering are
captured in the imbalance responsibility calculation of the balancing
area.
412. FirstEnergy states that Requirement R17 should include only
``control center devices'' instead of devices at each substation.
FirstEnergy states that accuracy at the substation level is unnecessary
and the costs to install automatic generation control equipment at each
substation would be high. FirstEnergy also states that the term
``check'' in Requirement R17 needs to be clarified.
413. California Cogeneration states that the Commission has
previously ruled that separate metering for the gross generation of a
customer-owned generator is not proper or necessary, and states that
the Commission should clarify that this Reliability Standard does not
establish metering requirements for individual generators, and does not
allow separate metering of generation and load on an end-user's
site.\191\
---------------------------------------------------------------------------
\191\ See California Cogeneration at 6, citing California
Independent System Operator Corp., Opinion No. 464, 104 FERC ]
61,196 (2003).
---------------------------------------------------------------------------
414. LPPC notes that BAL-005-0 has 17 requirements but no Measures,
and that it uses phrases such as ``adequate metering'' and ``burden on
the interconnection.'' LPPC contends that there is no definition for
these ambiguous terms and that there is no way to determine if terms
like ``adequate metering'' will mean the same thing in different parts
of the country or ensure consistent penalties will be assessed for the
same violation.
(b) Commission Determination
415. The Commission agrees with MISO that, while the number of
frequency deviations due to loss of generation has decreased, the
Commission is concerned with the implications of the actual data
presented by PJM that shows two frequency deviations each week day
without the loss of generation.\192\ This concern is supplemented by
documents that identify that some balancing authorities are restricting
automatic generation control actions during schedule changes.\193\
---------------------------------------------------------------------------
\192\ NOPR at n.134.
\193\ See R. L. Vice, Frequency Issues 2005, available at:
http://www.wecc.biz/documents/library/RITF/Frequency_Issues_2005_rev_0.pdf
.
---------------------------------------------------------------------------
416. Both Xcel and FirstEnergy question Requirement R17 but do not
oppose the Commission's proposal to approve this Reliability Standard.
Earlier in this Final Rule, we direct the ERO to consider the comments
received to the NOPR in its Reliability Standards development process.
Thus, the comments of Xcel and FirstEnergy should be addressed by the
ERO when this Reliability Standard is revisited as part of the ERO's
Work Plan.
417. California Cogeneration requests clarification that Commission
rulings made prior to the enactment of FPA section 215 would still be
applicable. The case cited by California Cogeneration was issued before
EPAct 2005 was enacted and gave the Commission direct responsibility
over
[[Page 16461]]
Bulk-Power System reliability. By its terms, BAL-005-0 requires each
generator operator with generating facilities operating within an
Interconnection to ensure that those generating facilities are included
within the metered boundaries of a balancing authority area. Therefore,
any generator that is subject to the Reliability Standards, as
discussed in the Applicability Issues section of this Final Rule,\194\
is subject to the metering requirements in this Reliability Standard.
Our conclusion, however, does not determine the appropriate ratemaking
treatment.
---------------------------------------------------------------------------
\194\ See Applicability Issues: Bulk-Power Ststem v. Bulk
Electric System and Applicability to Small Entities, supra sections
II.C.1-2.
---------------------------------------------------------------------------
418. With respect to LPPC's concern that terms used in the
Reliability Standard are not definitive when viewed individually, and
LPPC's statement that the Reliability Standard is ambiguous because it
does not include Measures, we disagree. The Commission finds each
Requirement of BAL-005-0 is clear and enforceable. The Requirements
provide sufficient guidance for an entity to understand its
obligations. When Measures are incorporated into the Reliability
Standard, the Measures will provide guidance on assessing non-
compliance with the Requirements. For these reasons and as previously
addressed in the NOPR, the Commission disagrees that the enforceable
obligations set forth in Requirements are unclear absent Measures.
419. The Commission notes that no one commented on the proposal to
include 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. The Commission adopts the NOPR proposal to require the ERO
to modifiy the Reliability Standards to include a Measure that provides
for a verification process over the minimum required automatic
generation control or regulating reserves a balancing authority
maintains. However, as discussed in the Common Issues section of this
Final Rule, we will leave it to the discretion of the ERO whether to
include other Measuers.\195\
---------------------------------------------------------------------------
\195\ See Common Issues Pertaining to Reliability Standards:
Measures and Levels of Non-Compliance, supra section II.E.2.
---------------------------------------------------------------------------
420. FirstEnergy has a number of suggestions to improve the
existing Reliability Standard and the ERO is directed to consider those
suggestions in its Reliability Standards development process.
v. Summary of Commission Determinations
421. The Commission approves 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 directs
the ERO to develop a modification to BAL-002-0 through the Reliability
Standards development process that: (1) Develops a process to calculate
the minimum regulating reserve a balancing authority must have at any
given time taking into account expected load and generation variation
and transactions being ramped into or out of the balancing authority;
(2) changes the title of the Reliability Standard to be neutral as to
the source of regulating reserves and to allow the inclusion of
technically qualified DSM and direct control load management; (3)
clarifies Requirement R5 of this Reliability Standard to specify the
required type of transmission or backup plans when receiving regulation
from outside the balancing authority when using non-firm service and
(4) includes Levels of Non-Compliance and a Measure that provides for a
verification process over the minimum required automatic generation
control or regulating reserves a balancing authority must maintain.
g. Inadvertent Interchange (BAL-006-1)
422. BAL-006-1 requires that each balancing authority calculate and
record inadvertent interchange on an hourly basis.
423. In the NOPR, the Commission proposed 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 proposed 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.\196\
---------------------------------------------------------------------------
\196\ NOPR at P 212.
---------------------------------------------------------------------------
424. In addition, the NOPR solicited comment on whether
accumulation of large amounts of inadvertent imbalances is a concern to
the industry and if so, options to address the accumulation.
i. Measures and Additional Levels of Non-Compliance Including Measures
Concerning the Accumulation of Large Inadvertent Imbalances
(a) Comments
425. Certain commenters \197\ do not support the Commission's
proposal to add Measures and additional Levels of Non-Compliance,
including Measures concerning the accumulation of large inadvertent
imbalances. Xcel states that such a measure would not enhance
reliability and involves primarily a commercial matter. MRO suggests
that large inadvertent balances are an equity issue and as such should
be addressed through business practices and not through the Reliability
Standards. MidAmerican states that no additional measures addressing
inadvertent imbalances are needed in this Reliability Standard because
the issue is adequately addressed in other Reliability Standards.\198\
MidAmerican states that if the Commission proceeds to require Measures
and Levels of Non-Compliance for large accumulations, it must insure
that no ``double penalties'' are imposed.
---------------------------------------------------------------------------
\197\ Xcel, MRO, MidAmerican and MISO-PJM.
\198\ MidAmerican explains that large interchange imbalances are
a result of telemetry failures, AGC misoperation or scheduling
errors and further states that BAL-001 addresses AGC performance and
the INT standards handle compliance with scheduling requirements.
---------------------------------------------------------------------------
426. EEI believes that the need to set a Measure for the
accumulation of large inadvertent imbalances may be premature. EEI
suggests that inadvertent energy is not a problem in real-time
operations and is the result of frequency over-bias. EEI further states
that if the Commission believes the industry should address both
inadvertent energy and frequency bias, the clear consequence is a
fundamental reconsideration of the control performance standard. EEI
strongly recommends that the Commission clarify whether it intends for
the industry to reconsider this fundamental reliability principle.
427. Constellation states some concern regarding the ability of
balancing authorities to make appropriate arrangements to settle
inadvertent imbalances. In particular, Constellation states that in
arranging bilateral paybacks, it is difficult to find a counterparty
with an opposite balance and there are transmission fees that further
hinder the process of these paybacks. Constellation states that the
Commission should require the industry to adopt procedures that will
better facilitate bilateral payback of inadvertent energy, such as
waiving the
[[Page 16462]]
scheduling requirement for small bilateral paybacks (such as WECC has
implemented).
428. TAPS repeats the arguments it made in its comments on the
Staff Preliminary Assessment that the existing treatment of balancing
authority inadvertent interchange is not comparable to the treatment of
energy imbalances. TAPS suggests that the Commission has an obligation
to do more than what is proposed in the NOPR, which states that the
issue is being addressed in the OATT reform docket \199\ while
approving Reliability Standards that perpetuate the preferential
treatment of balancing authority inadvertent interchange.\200\
---------------------------------------------------------------------------
\199\ OATT Reform NOPR at P 208.
\200\ NOPR at P 206.
---------------------------------------------------------------------------
(b) Commission Determination
429. The Commission directs the ERO to develop a modification to
BAL-006-1 that adds Measures concerning the accumulation of large
inadvertent imbalances and Levels of Non-Compliance. While we agree
that inadvertent imbalances do not normally affect the real-time
operations of the Bulk-Power System and pose no immediate threat to
reliability, we are concerned that large imbalances represent
dependence by some balancing authorities on their neighbors and are an
indication of less than desirable balancing of generation with load.
The Commission also notes that the stated purpose of this Reliability
Standard is to define a process for monitoring balancing authorities to
ensure that, over the long term, balancing authorities do not
excessively depend on other balancing authorities in the
Interconnection for meeting their demand or interchange obligations.
430. The Commission disagrees with MidAmerican that having Measures
in this Reliability Standard will result in double penalties. The
Commission believes that this Reliability Standard has an independent
reliability goal that ``define[s] a process for monitoring balancing
authorities to ensure that, over the long term, balancing authorities
do not excessively depend on other balancing authority areas in the
Interconnection for meeting their demand or interchange obligations.''
\201\
---------------------------------------------------------------------------
\201\ See BAL-006-1 (Inadvertent Interchange, Purpose
Statement).
---------------------------------------------------------------------------
431. The Commission agrees with EEI that one of the root causes of
inadvertent interchange is the difference between the actual frequency
response and the existing bias settings. The Commission has directed
that this cause be addressed in other BAL Reliability Standards. If the
industry wishes to propose alternative metrics to the control
performance Reliability Standards, the Commission suggests that it does
so through the ERO processes and that such changes include an
explanation of how the revised metrics would better measure the ability
of an individual balancing authority to match load and generation.
432. In response to Constellation's comment about the fees
associated with the settlement of inadvertent imbalances, the
Commission notes that this issue relates to business practices and
should be brought before NAESB or otherwise addressed in contexts other
than section 215 of the FPA.
433. With respect to TAPS' concerns regarding disparate treatment
of imbalances for non-control area utilities, the Commission is not
convinced that this is a reliability issue. As identified in Order No.
890, inadvertent interchange is not comparable to imbalances.\202\
---------------------------------------------------------------------------
\202\ See Order No. 890 at P 702-03.
---------------------------------------------------------------------------
434. Accordingly, the Commission adopts the proposal in the NOPR to
direct the ERO to develop Measures under this Reliability Standard to
ensure balancing authorities will not have large inadvertent
imbalances.
ii. Whether the Accumulation of Large Amounts of Inadvertent Imbalances
Is a Concern and Potential Options
(a) Comments
435. LPPC states that its members are concerned that large
inadvertent imbalances would be an indication of an underlying issue
related to overall balancing of resources and demand and suggests that
options to address these large inadvertent imbalances should be
addressed through the Reliability Standards development process.
436. NERC states that the performance requirements that relate to
reliability are addressed in BAL-001-0 and BAL-002-0 and the new
Reliability Standards which will replace them. Further, NERC states
that if the Commission wishes to direct consideration of limits on the
amount of inadvertent imbalances, such directive should be in the form
of an issue to be resolved or reliability objective to be achieved
rather than a specific requirement to set a fixed limit on inadvertent
accumulation.
437. TVA, MISO and MidAmerican state that the accumulation of large
inadvertent balances over time does not raise grid reliability issues.
TVA asserts that this is largely a financial matter. In addition, TVA
comments that if a balancing authority inappropriately uses the
interconnection in a way which results in a large inadvertent imbalance
this behavior should be reflected in the balancing authority's control
performance standard compliance. MISO states that some large amounts of
inadvertent imbalance are due to a balancing authority fulfilling its
bias obligation. MISO states that an arbitrary cap should not be a part
of this Reliability Standard.
(b) Commission Determination
438. As stated previously, while the Commission agrees that these
imbalances do not present an immediate reliability problem, we believe,
as stated by LPPC, that large interchange imbalances are indicative of
an underlying problem related to balancing of resources and demand. It
would be worthwhile for the ERO to examine the WECC time error
correction procedure.
439. Since the ERO indicates that the reliability aspects of this
issue will be addressed in a Reliability Standards filing later this
year, the Commission asks the ERO, when filing the new Reliability
Standard, to explain how the new Reliability Standard satisfies the
Commission's concerns.
iii. Summary of Commission Determinations
440. Accordingly, the Commission approves 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 directs the ERO to develop a modification to BAL-006-1
through the Reliability Standards development process that includes
Measures concerning the accumulation of large inadvertent imbalances
and additional Levels of Non-Compliance.
h. Regional Differences to BAL-006-1: Inadvertent Interchange
Accounting and Financial Inadvertent Settlement
441. The NOPR explained that BAL-006-1 provides for two regional
differences.\203\ First, a regional difference is provided 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
locational marginal pricing could be implemented to meet their
Commission directed market obligations. Subsequently, Southwest Power
Pool (SPP) requested,
[[Page 16463]]
and NERC approved, the same regional difference for.\204\
---------------------------------------------------------------------------
\203\ NOPR at P 216.
\204\ BAL-006-1, filed on August 28, 2006, would extend the
regional difference to SPP.
---------------------------------------------------------------------------
442. Second, the NOPR explained that a regional difference would
apply to the control area participants of MISO and SPP that would allow
each 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 therefore accumulation of net-interchange
would not affect the non-participant control areas.
443. The Commission proposed to approve these regional differences,
explaining that the two proposed regional differences relate solely to
facilitating financial settlements of accumulated inadvertent
interchange due to the physical differences of these areas and have
minimal, if any, reliability implications.
i. Comments
444. FirstEnergy notes that the two proposed regional differences
reference the Version 0 policies instead of the NERC Reliability
Standards and requests that the Commission direct NERC to revise the
regional differences accordingly. In addition, FirstEnergy states that
the Commission should direct NERC to define the function of a waiver.
FirstEnergy agrees that transferring responsibility for the tasks under
these waivers to the RTO is appropriate.
ii. Commission Determination
445. No commenter objected to the regional differences to BAL-006-
1. However, the Commission agrees with FirstEnergy that the regional
differences incorrectly reference retired policy terminology.
Therefore, the Commission approves the regional differences as
mandatory and enforceable under Order No. 672 as necessary due to the
physical differences between multiple balancing authorities and a
single market \205\ but the Commission directs the ERO to modify the
regional differences so that they reference the current Reliability
Standards and are in the standard form, which includes Requirements,
Measures and Levels of Non-Compliance. The ERO should explore
FirstEnergy's request to define the function of a waiver in its
Reliability Standards development process.
---------------------------------------------------------------------------
\205\ Order No. 672 at P 291.
---------------------------------------------------------------------------
2. CIP: Critical Infrastructure Protection
446. The goal of CIP-001-1 is to ensure that operating entities
recognize sabotage events and inform appropriate authorities and each
other to properly respond to the sabotage to minimize the impact on the
Bulk-Power System.\206\ The Reliability Standard requires that each
reliability coordinator, balancing authority, transmission operator,
generation operator and LSE have procedures for recognizing and for
making operating personnel aware of sabotage events, and communicating
information concerning sabotage events to appropriate ``parties'' in
the Interconnection.\207\
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\206\ The NOPR addressed CIP-001-0. On November 15, 2006, NERC
submitted for approval proposed Reliability Standard CIP-001-1,
which revised and replaced the previous version of the Reliability
Standard to include Measures and Levels of Non-Compliance.
\207\ On August 28, 2006, NERC submitted for approval proposed
Reliability Standards CIP-002-1 through CIP-009-1. These proposed
Reliability Standards, which relate to cybersecurity, are being
addressed in a separate rulemaking proceeding in Docket No. RM06-22-
000.
---------------------------------------------------------------------------
447. In the NOPR, the Commission proposed 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 proposed 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.
448. In the NOPR, the Commission explained that the Requirements of
CIP-001-0 refer to a ``sabotage event'' but do not define that term.
The Commission stated that, while ``sabotage'' is a commonly understood
term and the common understanding should suffice in most circumstances,
it was concerned that situations may arise in which it is not clear
whether action pursuant to CIP-001-0 is required. Thus, the NOPR
proposed that the ERO provide guidance clarifying the triggering event
for an entity to take action pursuant to CIP-001-0.
a. Comments
449. EEI and Entergy comment that they generally agree with the
Commission's perspective. While APPA and Six Cities support approving
CIP-001-1 as mandatory and enforceable, they ask that the Commission
defer the application of monetary penalties until further guidance is
provided on what events are reportable and what steps an entity must
take to be certain it is in compliance with the Reliability Standard.
Claiming that CIP-001-1 is too vague to be enforceable, TAPS opposes
approval until NERC has further defined ``sabotage'' and the facilities
to which the Reliability Standard applies.
450. APPA questions whether CIP-001-1 should apply to LSEs (LSEs)
contending that, unlike transmission owners and generators, LSEs do not
own or operate ``hard assets'' that are normally thought of ``at risk''
to sabotage. It claims that compliance would be particularly burdensome
for small LSEs, such as the requirement to provide a preliminary report
within one hour of an event. APPA states that NERC should therefore
reconsider whether LSEs should be required to comply with this
Reliability Standard. Further, while APPA supports the application of
CIP-001-1 to larger generators and any unit required for reliable
interconnected operations, it questions whether it is critical to
extend the Reliability Standard to all generator operators--noting that
there are 3,564 generating plants in the United States with a total
capacity of 75 MW or less. APPA contends that the incremental benefits
of requiring all generators to comply with CIP procedures seem minimal
since many facilities are unlikely to have a material impact on Bulk-
Power System reliability or be a target for sabotage in the first
place. APPA suggests that the Commission defer action on CIP-001-1
while it implements a prioritization plan.
451. TAPS and California Cogeneration are also concerned about
applicability and contend that compliance should be limited to those
that have a significant or material impact on Bulk-Power System
reliability. Both are concerned that compliance with this Reliability
Standard would create significant administrative burdens and
documentation requirements that are not justified where a facility does
not have a material impact on the Bulk-Power System. California
Cogeneration suggests that CIP-001-1 be revised to: (1) Exclude
generator output used on-site and (2) provide a mechanism for
determining that a facility has no material impact and thus is exempt
from compliance.
452. A number of commenters agree with the Commission's concern
that the term ``sabotage'' needs to be better defined and guidance
provided on the triggering events that would cause an
[[Page 16464]]
entity to report an event.\208\ FirstEnergy states that this definition
should differentiate between cyber and physical sabotage and should
exclude unintentional operator error. It advocates a threshold of
materiality to exclude acts that do not threaten to reduce the ability
to provide service or compromise safety and security. SoCal Edison
states that clarification regarding the meaning of sabotage and the
triggering event for reporting would be helpful and prevent over-
reporting.
---------------------------------------------------------------------------
\208\ See, e.g., APPA, FirstEnergy, SoCal Edison, Six Cities and
TAPS.
---------------------------------------------------------------------------
453. APPA comments that Requirement R1 of CIP-001-1, which provides
that an entity must have procedures for recognizing sabotage events and
making its personnel aware of sabotage events, while a ``good first
step,'' lacks sufficient detail upon which the ERO can base compliance
and enforcement efforts. It characterizes CIP-001-1 as an ``entity-
specific `fill-in-the-blank' standard'' that does not provide
sufficient direction or guidance for an entity to determine whether it
is in compliance. APPA further states that Measure M1 provides no
criteria for a Regional Entity, acting in its capacity as a compliance
monitor, to make an objective determination that an entity's sabotage
procedure is adequate.
454. In response to the Commission's concern regarding the need for
periodic review of sabotage response procedures, FirstEnergy suggests
that CIP-001-1 should define what time period is sufficient for
periodic reviews and suggests that a bi-annual review would be
appropriate. MRO believes that a requirement to annually review the
sabotage response procedures should be added to the Reliability
Standard.
455. NERC objects to the wording of the Commission's proposed
directive that NERC modify CIP-001-1 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. NERC states the Commission's directive is overly prescriptive
because it specifies language to be included in the standard and
thereby circumvents the Reliability Standards development process.
Further, NERC objects that this directive would require entities in
other nations such as Canada or Mexico to report to the U.S. Department
of Homeland Security. Santa Clara suggests that Requirement R4 (and
corresponding measure M3) should be modified to state that ``* * *
contacts should be established with the appropriate public safety
officials or directly with the local Federal Bureau of Investigation
(FBI) or Royal Canadian Mounted Police (RCMP) such that communication
channels are established to report incidents to the appropriate
authority.'' It states that, in the case of a municipal utility that is
part of a local governmental agency that already has a public safety
department which is in regular contact with the local FBI, and where
clear communication channels already exist between the public safety
department and the utility, it would be redundant for the utility to
establish a direct link to the FBI for reporting purposes. Xcel also
suggests that the term ``appropriate federal authorities'' should be
modified to avoid conflict with established processes now in place, and
that the term should be specifically identified so the Requirements on
affected entities are clear.
456. Process Electricity Committee advocates approval of CIP-001-0
as initially proposed by NERC without modification, but it objects to
the revised CIP-001-1 as placing an undue burden on smaller entities.
It is concerned that the Commission's proposal to require mandatory
reporting to appropriate federal authorities within a specific time
frame will impose substantial burdens on end users with little or no
discernable benefit. It states that there is no evidence that any
entities--both regulated and unregulated--under-report sabotage events.
Further, according to Process Electricity Committee, the adoption of
uniform requirements could require end users to modify existing
security programs and procedures that are designed to protect
industrial facilities, whereas the utility generator requirements could
be conflicting or duplicative.
457. Entergy and FirstEnergy express concern that there is a
potential for redundancy between CIP-001-1 and other related federal
reporting standards. Entergy states that NERC should consider ensuring
that CIP-001-1 is consistent with, but not duplicative of, these other
requirements. FirstEnergy states that both the Department of Energy
(DOE) and the Energy Information Administration (EIA) impose reporting
requirements that are similar to CIP-001-1 and suggests that to avoid
conflicts the reporting requirements under this Reliability Standard
should be conformed to the existing DOE and EIA requirements. It also
states that nuclear units have their own set of operating requirements,
including procedures for reporting sabotage, and suggests that a
company's compliance with NRC procedures should be presumed to meet
NERC standards. EEI, FirstEnergy and Xcel suggest greater coordination,
possibly with all events being reported to NERC, which would then
coordinate with federal authorities. Xcel suggests the development of a
single sabotage reporting form to streamline the reporting process and
make it easier for affected entities to provide reports in a timely
manner.
458. APPA and FirstEnergy express concern about a requirement to
report an act of sabotage within a fixed period of time. Xcel states
that the triggering event for disclosure of an act of sabotage often
will be unclear and that an investigation will take time especially if
the event occurs at an unstaffed or remote facility. Thus, Xcel does
not believe that the standard should contain an express time limit for
reporting an act of sabotage since the amount of time necessary to make
that report may vary depending on the circumstances. FirstEnergy
suggests that CIP-001-1 should define the specified period for
reporting an incident beginning from when the event is discovered or
suspected to be sabotage. APPA is also concerned that a specific time
limit for a report (such as a 60 minute requirement) would be
burdensome to meet for a small LSE that is not continuously staffed
when a triggering event occurs outside staffed hours.
b. Commission Determination
i. Applicability to Small Entities
459. The Commission acknowledges the concerns of the commenters
about the applicability of CIP-001-1 to small entities and has
addressed the concerns of small entities generally earlier in this
Final Rule. Our approval of the ERO Compliance Registry criteria to
determine which users, owners and operators are responsible for
compliance addresses the concerns of APPA and others.
460. However, the Commission believes that there are specific
reasons for applying this Reliability Standard to such entities, as
discussed in the NOPR. APPA indicates that some small LSEs do not own
or operate ``hard assets'' that are normally thought of as ``at risk''
to sabotage. The Commission is concerned that, an adversary might
determine that a small LSE is the appropriate target when the adversary
aims at a particular population or facility. Or an adversary may target
a small user, owner or operator because it may have similar equipment
or protections as a larger facility, that is, the adversary may use an
attack against a smaller facility as a training ``exercise.'' The
knowledge of sabotage events that occur at any facility
[[Continued on page 16465]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 16465-16514]] Mandatory Reliability Standards for the Bulk-Power System
[[Continued from page 16464]]
[[Page 16465]]
(including small facilities) may be helpful to those facilities that
are traditionally considered to be the primary targets of adversaries
as well as to all members of the electric sector, the law enforcement
community and other critical infrastructures.
461. For these reasons, the Commission remains concerned that a
wider application of CIP-001-1 may be appropriate for Bulk-Power System
reliability. Balancing these concerns with our earlier discussion of
the applicability of Reliability Standards to smaller entities, we will
not direct the ERO to make any specific modification to CIP-001-1 to
address applicability. However, we direct the ERO, as part of its Work
Plan, to consider in the Reliability Standards development process,
possible revisions to CIP-001-1 that address our concerns regarding the
need for wider application of the Reliability Standard. Further, when
addressing such applicability issues, the ERO should consider whether
separate, less burdensome requirements for smaller entities may be
appropriate to address these concerns.
ii. Definition of Sabotage
462. Several commenters agree with the Commission's concern that
the term ``sabotage'' should be defined. For the reasons stated in the
NOPR, we direct that the ERO further define the term and provide
guidance on triggering events that would cause an entity to report an
event.\209\ However, we disagree with those commenters that suggest the
term ``sabotage'' is so vague as to justify a delay in approval or the
application of monetary penalties. As explained in the NOPR, we believe
that the term sabotage is commonly understood and that common
understanding should suffice in most instances.\210\ Further, in the
interim while the matter is being addressed by the Reliability
Standards development process, we direct the ERO to provide advice to
entities that have concerns about the reporting of particular
circumstances as they arise.
---------------------------------------------------------------------------
\209\ See NOPR at P 224.
\210\ Id. at P 224, n.140, quoting a dictionary definition of
``sabotage'' as ``destruction of property or obstruction of normal
operations, as by civilians or enemy agents. * * *''
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463. Further, in defining sabotage, the ERO should consider
FirstEnergy's suggestions to differentiate between cyber and physical
sabotage and develop a threshold of materiality. However, regarding the
latter suggestion, the Commission directs that guidance for a threshold
of materiality must be designed carefully to mitigate the risk that an
unsuccessful sabotage event is not correctly reported because it did
not cause sufficient harm.
iii. Procedures for Recognizing Sabotage Events
464. Requirement R1 of CIP-001-1 provides that an applicable entity
must have procedures ``for the recognition of and for making their
operational personnel aware of sabotage events on its facilities and
multi-site sabotage affecting larger portions of the Interconnection.''
The NOPR expressed concern that the provision does not establish
baseline requirements regarding what issues should be addressed by the
developed procedures. APPA goes even further and, characterizing it as
an entity specific fill-in-the-blank standard, contends that it lacks
sufficient detail upon which the ERO can base compliance and
enforcement efforts.
465. While the Commission believes that this Reliability Standard
can and should be enhanced by specifying baseline requirements
regarding what issues should be addressed in the procedures for
recognizing sabotage events and making personnel aware of such events,
it disagrees with APPA that Requirement R1 lacks sufficient detail on
which to base ERO compliance and enforcement efforts. As indicated in
Measure M1, an applicable entity must have and maintain the procedure
as defined by Requirement R1. Thus, if an applicable entity cannot
provide the required procedure to the ERO or a Regional Entity auditor
upon request, it would likely be subject to an enforcement action.
While we expect that an applicable entity that has made a good faith
effort to develop a meaningful procedure to comply with Requirement R1
(and Measure M1) would not be subject to an enforcement action, an ERO
or Regional Entity audit team may provide steps to improve the
individual entity's procedure, which would serve as a baseline for that
entity for any subsequent audit. Such an approach would be acceptable
and allow for meaningful compliance in the interim until CIP-001-1 is
modified pursuant to our directive.
iv. Periodic Review of Sabotage Reporting Plans
466. The Commission was concerned that CIP-001-1 did 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.\211\ In response, FirstEnergy suggests that a bi-annual review
would be appropriate and MRO believes that an annual review requirement
should be added to the Reliability Standard. Periodic testing of the
procedures through an exercise would assist in determining if the
procedures are adequate for achieving the desired result. Lessons
learned from these events would help in developing or modifying the
sabotage reporting procedures.
---------------------------------------------------------------------------
\211\ NOPR at P 228.
---------------------------------------------------------------------------
467. The Commission affirms the NOPR directive and directs the ERO
to incorporate a periodic review or updating of the sabotage reporting
procedures and for the periodic testing of the sabotage reporting
procedures. At this time, the Commission does not specify a review
period as suggested by FirstEnergy and MRO and, rather, believes that
the appropriate period should be determined through the ERO's
Reliability Standards development process. However, the Commission
directs that the ERO begin this process by considering a staggered
schedule of annual testing of the procedures with modifications made
when warranted formal review of the procedures every two or three
years.
v. Mandatory Reporting of a Sabotage Event
468. CIP-001-1, Requirement R4, requires that each applicable
entity establish communications contacts, as applicable, with the local
FBI or Royal Canadian Mounted Police officials and develop reporting
procedures as appropriate to its circumstances. The Commission in the
NOPR expressed concern that the Reliability Standard does not require
an applicable entity to actually contact the appropriate governmental
or regulatory body in the event of sabotage. Therefore, the Commission
proposed that NERC 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.'' \212\
---------------------------------------------------------------------------
\212\ Id. at P 231.
---------------------------------------------------------------------------
469. As mentioned above, NERC and others object to the wording of
the proposed directive as overly prescriptive and note that the
reference to ``appropriate federal authorities'' fails to recognize the
international application of the Reliability Standard. The example of
the Department of Homeland Security as an ``appropriate federal
authority'' was not intended to be an exclusive designation.
Nonetheless, the Commission agrees that a reference to ``federal
authorities''
[[Page 16466]]
could create confusion. Accordingly, we modify the direction in the
NOPR and now direct the ERO to address our underlying concern regarding
mandatory reporting of a sabotage event. The ERO's Reliability
Standards development process should develop the language to implement
this directive.
470. As noted above, FirstEnergy, EEI and others express concern
regarding the potential for redundant reporting under CIP-001-1 and
other government reporting standards, and the need for greater
coordination. The Commission understands the concern about multiple
reporting channels that may arise and the burden that this may present
to applicable entities. We direct the ERO to explore ways to address
these concerns--including central coordination of sabotage reports and
a uniform reporting format--in developing modifications to the
Reliability Standard with the appropriate governmental agencies that
have levied the reporting requirements.
471. The Commission stated that the reporting of a sabotage event
should occur within a fixed period of time, and referred to a Homeland
Security procedure that references a 60-minute period for submitting a
preliminary report and a follow-up report within four to six
hours.\213\ While commenters raise a number of concerns about the need
for fairness in the implementation of such a requirement, they do not
challenge the NOPR's underlying concern or the appropriateness of such
a provision. The Commission believes that an applicable entity should
report a sabotage event in a timely manner to allow government
authorities and critical infrastructure members the opportunity to
react in a meaningful manner to such information. Thus, the Commission
directs the ERO to modify CIP-001-1 to require an applicable entity to
contact appropriate governmental authorities in the event of sabotage
within a specified period of time, even if it is a preliminary report.
The ERO, through its Reliability Standards development process, is
directed to determine the proper reporting period. In doing so, the ERO
should consider suggestions raised by commenters such as FirstEnergy
and Xcel to define the specified period for reporting an incident
beginning from when an event is discovered or suspected to be sabotage,
and APPA's concerns regarding events at unstaffed or remote facilities,
and triggering events occurring outside staffed hours at small
entities.
---------------------------------------------------------------------------
\213\ Id. at n.142.
---------------------------------------------------------------------------
c. Summary of Commission Determinations
472. As explained in the NOPR, while the Commission has identified
concerns regarding CIP-001-1, 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. Accordingly, the Commission approves Reliability Standard CIP-
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, the
Commission directs the ERO to develop the following modifications to
the Reliability Standard through the Reliability Standards development
process: (1) Further define sabotage and provide guidance as to the
triggering events that would cause an entity to report a sabotage
event; (2) specify baseline requirements regarding what issues should
be addressed in the procedures for recognizing sabotage events and
making personnel aware of such events; (3) incorporate a periodic
review or updating of the sabotage reporting procedures and for the
periodic testing of the sabotage reporting procedures and (4) require
an applicable entity to contact appropriate governmental authorities in
the event of sabotage within a specified period of time. In addition,
we direct the ERO, as part of its Work Plan, to consider revisions to
CIP-001-1 that address our concerns regarding applicability to smaller
entities. The ERO should also consider consolidation of the sabotage
reporting forms and the sabotage reporting channels with the
appropriate governmental authorities to minimize the impact of these
reporting requirements on all entities.
3. COM: Communications
473. The Communications (COM) group contains two Reliability
Standards. The first 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 to address real-time
emergencies and that operating personnel carry out effective
communications.
474. The NOPR contained a discussion of how the transmission
operator and generator operator function would apply to RTO, ISO and
pooled resource organizations. In this Final Rule, conclusions
concerning those issues are covered in the Applicability Issues
section.\214\ In essence, an organization may, but does not have to,
accept compliance responsibility on behalf of its members. Since
telecommunication is vital to the Reliable Operation of the Bulk-Power
System, the Commission finds that it is not permissible to have either
unnecessary overlaps or gaps in telecommunications.
---------------------------------------------------------------------------
\214\ See Applicability Issues: Use of the NERC Functional
Model, supra section II.C.4.
---------------------------------------------------------------------------
a. Telecommunications (COM-001-1)
475. COM-001-0 \215\ seeks to ensure coordinated telecommunications
among operating entities, which are 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.
---------------------------------------------------------------------------
\215\ In its November 15, 2006, filing, NERC submitted COM-001-
1, which supercedes the Version 0 Reliability Standard. COM-001-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, COM-001-1.
---------------------------------------------------------------------------
476. The Commission proposed to approve Reliability Standard COM-
001-0 as mandatory and enforceable. In addition, the Commission
proposed 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 providers as applicable entities
and (3) includes Requirements for communication facilities for use
during emergency situations.
477. In addition, the Commission sought comments on specific
requirements or performance criteria for telecommunications facilities,
noting that COM-001-0 might be improved by providing specific
requirements for adequacy, redundancy, diverse routing, and periodic
testing. The Commission also sought comments on whether the relative
roles of applicable entities should be considered when setting down
requirements for telecommunication facilities, since the needs will
vary based on role.
[[Page 16467]]
478. Most comments address the specific modifications and concerns
raised by the Commission in the NOPR. Below, we address each topic
separately, followed by a summary of our conclusions.
i. Applicability to Generator Operators and Distribution Providers and
their Telecommunications Facility Requirements
479. The Commission stated in the NOPR that communications with
generator operators and distribution providers are necessary to
maintain system reliability during normal and emergency situations,
while recognizing that telecommunication facility needs will vary
between these two entities and other reliability entities such as
reliability coordinators, transmission operators and balancing
authorities. The Requirements for each of these entities will vary
according to its respective roles.
(a) Comments
480. EEI supports the goals stated by the Commission with regard to
COM-001-1, in particular, the need to apply this Reliability Standard
to distribution providers. TVA agrees with the Commission's reasoning
that generator operators and distribution providers should be subject
to this Reliability Standard, but seeks clarification that such
entities may transfer their responsibility for data sharing with and
reporting to NERC and Regional Entities by contract to another entity.
481. In contrast, MRO, APPA, TAPS and SDG&E indicate that applying
this Reliability Standard to generator operators and distribution
providers may not be appropriate. APPA argues generator operators and
distribution providers do not affect the Bulk-Power System in the same
manner as a reliability coordinator, balancing authority or
transmission provider does, since generator operators and distribution
providers only have a secondary or support role with respect to
reliability of the Bulk-Power System.
482. Further, APPA and SDG&E are concerned that the Commission's
proposal would unnecessarily subject generator operators and
distribution providers to Requirements that were designed for
transmission operators. For example, APPA indicates that NERCNet was
designed as part of the NERC Interregional Security Network for
communications among reliability coordinators, balancing authorities
and transmission operators, and was not designed to connect generators
to their balancing authorities and distribution providers to their
transmission operators. Further, SDG&E submits that, while generator
operators and distribution providers may logically have some role in
enabling communications that help ensure reliability, SDG&E sees no
basis for subjecting such entities to the same, extensive requirements
incumbent on transmission operators.
483. APPA argues that, while telecommunications Reliability
Standards with generator operators and distribution providers as
applicable entities may be needed, they are already subject to
telecommunications requirements as part of their bilateral
interconnection agreements with balancing authorities and transmission
providers. It contends that if NERC deems it necessary, a separate
Reliability Standard should be developed to govern telecommunications
between balancing authorities and generator operators, and between
transmission operators and distribution providers under their
respective footprints.
484. TAPS states that Requirement R1.4 has an ambiguous requirement
\216\ that, if applied to distribution providers and generator
operators, would impose redundancy requirements well beyond what is
reasonably necessary for Bulk-Power System reliability. Further it
asserts that the NOPR provides no basis for expanding the Reliability
Standard to small entities, such as a 2-MW distribution provider or
generator, much less than one that has no connection to the bulk
transmission system. Finally, TAPS contends that, in making this
proposal, the Commission is ``over-stepping its bounds'' by not leaving
it to the ERO's expert judgment whether COM-001-1 has sufficient
coverage to protect Bulk-Power System reliability and states that, in
any event, applicability should be limited through NERC's registry
criteria and definition of bulk electric system.
---------------------------------------------------------------------------
\216\ COM-001-1 Requirement R1.4 states: ``Where applicable,
these [telecommunications] facilities shall be redundant and
diversely routed.''
---------------------------------------------------------------------------
485. MRO further states that applying this Reliability Standard to
generator operators and distribution providers and including
Requirements for communication facilities for use during emergency
situations may also not be appropriate if the distribution provider
does not operate its own systems.
486. California PUC believes that the Commission's assertion of
authority to impose Reliability Standards applicable to either
generator operators or distribution providers should be extremely
limited, and should be based on an essential nexus between the proposed
Reliability Standard and the operation of the Bulk-Power System. It
contends that this aspect of the Commission's proposed directive is
duplicative and unnecessary when applied to entities in California, and
risks being counterproductive unless applied with considerable
restraint since California PUC's Operation Standards require power
plants to maintain the ability to communicate with the balancing
authority at all times, and to plan for the continuity of
communications during emergencies.
487. Process Electricity Committee agrees that the extent and
maintenance of telecommunication facilities should vary based on the
operator's potential affect on system reliability. It points out that
existing regulations and contractual obligations already require end
users to maintain adequate communications facilities. Further, it
states that on-site generation interconnected with the electricity grid
typically is required to maintain sufficient telecommunications
facilities between the generator owner or operator and the grid
operator. In the absence of evidence that this arrangement is
inadequate, Process Electricity Committee recommends that the amended
COM Reliability Standards be clarified so that they do not impose new
requirements on end users and other entities that have only minimal
impact on the reliability of the interconnected transmission network.
(b) Commission Determination
488. The Commission reaffirms its position that generator operators
and distribution providers should be included as applicable entities in
COM-001-1 to ensure there is no reliability gap during normal and
emergency operations. For example, during a blackstart when normal
communications may be disrupted, it is essential that the transmission
operator, balancing authority and reliability coordinator maintain
communications with their distribution providers and generator
operators. However, the current version of Reliability Standard COM-
001-1 does not require this because it does not include generator
operators and distribution providers as applicable entities. We clarify
that the NOPR did not propose to require redundancy on generator
operators' or distribution providers' telecommunication facilities or
that generator operators or distribution providers be trained on
anything not related to their functions during normal and emergency
conditions. We expect the telecommunication requirements for all
applicable entities will vary according to their roles and that these
[[Page 16468]]
requirements will be developed under the Reliability Standards
development process.
489. As stated in the Applicability Issues section of this Final
Rule, entities may share responsibility for complying with Reliability
Standards and the ERO's registration process takes this into
account.\217\ We believe that this satisfies TVA's concern about data
sharing and reporting responsibilities and MRO's concern about applying
this Reliability Standard to distribution providers only if they
operate their own systems.
---------------------------------------------------------------------------
\217\ See Applicability Issues: Applicability to Small Entities,
supra section II.C.2.
---------------------------------------------------------------------------
490. The Commission agrees with APPA that the primary purpose of
Requirement R6 is to provide information to ensure reliable
interregional operations and therefore should not apply to generator
operators and distribution providers. However, we disagree that this
leads to the conclusion that generator operators and distribution
providers should not be included in COM-001-1. As we have stated,
telecommunication requirements for all applicable entities will vary
according to their roles. In modifying COM-001-1 through the
Reliability Standards development process, the Commission believes that
the ERO should create appropriate telecommunications requirements for
generator operators and distribution providers, which may be additional
and separate Requirements to COM-001-1 or, alternatively, a new
Reliability Standard as suggested by APPA.
491. In response to SDG&E, the Commission's intent is not to
subject generator operators and distribution providers to the same
requirements placed on transmission operators. As part of the
modification of this Reliability Standard or development of a new
Reliability Standard to include the appropriate telecommunications
facility requirements for generator operators and distribution
providers, the ERO should take into account what would be required of
generator operators and distribution providers in terms of
telecommunications for the Reliable Operation of the Bulk-Power System,
instead of applying the same requirements as are placed on other
reliability entities such as reliability coordinators, balancing
authorities and transmission operators.
492. With regard to TAPS's comment, the Commission has identified a
concern and directs that the ERO address the matter through its
Reliability Standards development process. This comports with section
215(d)(5) of the FPA which authorizes the Commission, upon its own
motion, to order the ERO ``to submit to the Commission a proposed
Reliability Standard or a 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.''
We have identified such a matter and have left to the ERO to develop a
specific proposal by invoking its Reliability Standards development
process. Further, consistent with our discussion above regarding
applicability of Reliability Standards, applicability would be limited
through NERC's registry criteria and definition of bulk electric system
at this time.
493. In response to California PUC, in this Final Rule we are
initially limiting the applicability of these Reliability Standards to
those users, owners and operators of the Bulk-Power System on the ERO's
compliance registry. The Commission notes that it has jurisdiction
under section 215 of the FPA over all users, owners and operators of
the Bulk-Power System to ensure Reliable Operation of the Bulk-Power
System. To ensure reliability, it is important to include appropriate
generator operators and distribution providers as applicable entities
in Reliability Standard COM-001-1. However, any generator operator or
distribution provider that is not a user, owner or operator of the
Bulk-Power System will not be included. Also, at this time, the Bulk-
Power System is defined on the basis of the ERO's definition of the
``bulk electric system.'' The Commission believes that this should
satisfy California PUC's concern that this Reliability Standard be
limited to Bulk-Power System operations. We will not further limit our
directive as to which entities this Reliability Standard should apply.
494. As we explained in the NOPR, communication with generator
operators and distribution providers becomes especially important
during an emergency when generators with black start capability must be
placed in service and nearby loads restored as an initial step in
system restoration. This occurs at a critical time when normal
communication paths may be disrupted. While many generator operators
and distribution providers may have telecommunications requirements
pursuant to a bilateral contract as indicated by APPA, it is important
that all generator operators and distribution providers identified by
the ERO through its registration process are subject to uniform
telecommunications requirements. Therefore, we adopt our proposal to
require the ERO to modify COM-001-1 to apply to generator operators and
distribution providers. However, we recognize that some of the existing
requirements (such as Requirement R6 related to NERCNet) need not apply
to generator operators and distribution providers. In light of
commenters' concerns, as an alternative, it would be acceptable for the
ERO to develop a new Reliability Standard that would specifically
address an appropriate range of Requirements for telecommunication
facilities of generator operators and distribution providers that
reflect their respective roles on Reliable Operation of the Bulk-Power
System.
ii. Requirements for Telecommunications Facilities
495. The Commission sought comment on specific requirements or
performance criteria for telecommunication facilities and whether the
modified Reliability Standard should provide requirements that also
consider the relative role of applicable entities.
(a) Comments
496. A number of commenters agree with the Commission that the
relative role of an entity should be taken into account when specifying
the requirements for its telecommunications facilities.\218\ For
example, ISO-NE states that a single generator operator will not need
the level of redundancy and diverse routing that a reliability
coordinator needs.
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\218\ See, e.g., EEI, International Transmission, ISO-NE,
Process Electricity Committee and SoCal Edison.
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497. Many commenters recommend that telecommunications facilities
requirements should be specified in broad terms. EEI, APPA, Alcoa,
International Transmission, LPPC and SoCal Edison believe that revision
to COM-001-1 should provide specific or minimum requirements for
adequacy, redundancy and diverse routing. However, EEI, Alcoa and
Northern Indiana maintain that entities should have flexibility in
meeting the requirements and to allow for innovative technological
advancements. Alcoa and Northern Indiana maintain that without
flexibility, an applicable entity may choose a less optimal solution
just to comply with the Reliability Standard. EEI asserts that such
flexibility will also permit alternative means of implementing the
requirements that will translate into cost savings. International
Transmission
[[Page 16469]]
cautions that we should not prejudice the modification of this
Reliability Standard by indicating the specific requirements or the
performance criteria.
498. APPA states that, because the communications requirements for
an entity that is responsible for serving 3,000 MW of load is
distinctly different from another entity that serves 30 MW of load, the
ERO should take the size of the entity into consideration.
499. NERC believes that the questions posed by the NOPR regarding
performance criteria should be considered through the Reliability
Standards development process, in accordance with NERC's Work Plan,
which will allow a broader industry debate on the requirements for
telecommunications facilities. This approach will avoid any potential
conflicts with the requirements already established in the
telecommunications industry and by the Institute of Electrical and
Electronics Engineers.
500. Entergy states that it is unclear what cyber assets are
covered by COM-001-0. Entergy believes that the Reliability Standard
should focus on telecommunications that support the operation of
critical assets. Entergy also believes that COM-001-0 should be
expanded to include advances in communications technology. It states
that NERC should consider addressing the following in a way that will
facilitate an understanding of the Reliability Standards' requirements:
(1) Voice communications; (2) command and control data communications;
(3) security coordination data communications; (4) digital messaging
communications; (5) human linguistic convention and (6) other types of
communications, including video conferencing and communications with
remote security cameras. Entergy believes that this could be
accomplished through an enhancement to the definition of communications
in the NERC glossary and recasting COM-001-0 to improve the specificity
of requirements for each form of communication. Finally, Entergy
believes that Requirement R4 of COM-001-0, which requires reliability
coordinators, transmission operators and balancing authorities to use
English in all types of communications, should apply only to verbal and
written communications.
501. FirstEnergy asserts that the Requirement R2 is unclear because
it does not specify whether the phrase ``telecommunication facilities''
covers both voice and data facilities in the context of alarms. It
states that, although the word ``telecommunications facilities'' is
generally understood to mean both voice and data facilities, the
current practice is to display alarms only for data facilities.
Requirement R2 could be misinterpreted to require alarms on voice
facilities as well, which would be impractical.
502. Six Cities is concerned that the scope of improper conduct
under the ``NERCNet security policy'' in Attachment 1 is virtually
limitless \219\ Six Cities recognizes that it would be difficult to
provide a comprehensive and detailed list of all conduct that might be
considered a misuse of NERCNet data, but that difficulty does not
justify exposing NERCNet users to the risk of monetary penalties based
on amorphous and unbounded descriptions of potentially violative
conduct. Six Cities states that one solution would be to limit the
imposition of monetary penalties for misuse of NERCNet data to
instances where such misuse is intentional or grossly negligent.
According to Six Cities, it would be appropriate to exact a monetary
penalty where a NERCNet user deliberately uses NERCNet data for
unauthorized or unreasonable purposes. Six Cities asks that it be
modified to provide for a warning for the improper disclosure of
NERCNet data where the disclosure was not intentional or grossly
negligent.
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\219\ Attachment 1 provides that Violations of the NERCNet
Security Policy shall include, but not be limited to any act that:
Exposes NERC or any user of the NERCNet to actual or potential
monetary loss through the compromise of data security or damage.
Involves the disclosure of trade secrets, intellectual property,
confidential information or the unauthorized use of data.
Involves the use of data for illicit purposes, which may include
violation of any law, regulation or reporting requirement of any law
enforcement or government body.
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(b) Commission Determination
503. The Commission adopts its NOPR proposal that
telecommunications facility requirements must reflect the roles of the
respective operating or reliability entities that are included in the
applicability section in this Reliability Standard and how they would
affect the reliability of the Bulk-Power System. We note that most
commenters agree with this approach.
504. The Commission agrees with commenters that flexibility is
important in setting telecommunications requirements in order to foster
innovation, allow the adoption of new technologies and provide for
cost-effective solutions for compliance with the Reliability Standard.
However, the Commission finds that certain modifications to COM-001-1
are necessary to ensure system reliability. We believe that the ERO
must specify requirements for using telecommunications facilities
during normal and emergency conditions that: (1) Reflect the roles of
the applicable entities and their impact on Reliable Operation and (2)
include adequate flexibility. Accordingly, the Commission directs the
ERO to modify COM-001-1 through the Reliability Standards development
process to address our concerns. The Commission believes that the
concerns of Entergy and FirstEnergy are best addressed by the ERO in
the Reliability Standards development process.
505. Six Cities suggests specific new improvements to COM-001-1. As
stated above, such comments should be addressed as the ERO modifies the
Reliability Standards in the Reliability Standards development process.
iii. Measures and Levels of Non-Compliance
506. In its November 15, 2006, filing, NERC submitted COM-001-1,
which supersedes the Version 0 Reliability Standard. COM-001-1 adds
Measures and Levels of Non-Compliance to the Version 0 Reliability
Standard.
(a) Comments
507. ISO-NE notes that Compliance 1.1 of COM-001-0 specifies that
``Regional Reliability Organizations shall be responsible for
compliance monitoring * * *.'' ISO-NE suggests that since NERC designed
and created NERCNet, NERC should be responsible for maintaining and
ensuring the compliance with the Reliability Standard rather than
regional reliability organizations. ISO-NE recommends that the
Commission direct NERC to modify Compliance 1.1 to provide that NERC
shall be responsible for monitoring compliance of the NERCNet user
organizations.
(b) Commission Determination
508. With respect to ISO-NE's comment, we find that a regional
reliability organization does not have any role with compliance
matters; that role is reserved for the ERO or the Regional Entities.
However, we disagree with ISO-NE that the ERO must replace the regional
reliability organization as the compliance monitor. The fact that NERC
designed and created NERCNet does not require the ERO to be the
compliance monitor. Section 215 of the FPA states that the ERO may
delegate compliance and enforcement authority to a Regional Entity,
even if the ERO creates the Reliability Standards. Therefore, although
we direct that the
[[Page 16470]]
regional reliability organization should not be the compliance monitor
for NERCNet, we leave it to the ERO to determine whether it is the
appropriate compliance monitor or if compliance should be monitored by
the Regional Entities for NERCNet User Organizations.
iv. Summary of Commission Determination
509. While the Commission has identified a number of concerns with
regard to COM-001-1, this Reliability Standard is independently
enforceable without the modifications we are directing. Therefore, the
Commission approves Reliability Standard COM-001-1 as mandatory and
enforceable. Because of the importance of this Reliability Standard in
requiring transmission operators and others to have necessary
telecommunications equipment, we additionally, pursuant to section
215(d)(5) of the FPA and Sec. 39.5(f) of our regulations, direct the
ERO to develop a modification to COM-001-1 through the Reliability
Standards development process that: (1) Expands the applicability to
include generator operators and distribution providers and includes
Requirements for their telecommunications facilities; (2) identifies
specific requirements for telecommunications facilities for use in
normal and emergency conditions that reflect the roles of the
applicable entities and their impact on Reliable Operation and (3)
includes adequate flexibility for compliance with the Reliability
Standard, adoption of new technologies and cost-effective solutions. As
an alternative to applying this Reliability Standard to generator
operators and distribution providers, the ERO may develop a new
Reliability Standard that will address the Requirements for
telecommunication facilities applicable to generator operators and
distribution providers.
b. Communications and Coordination (COM-002-2)
510. COM-002-2 \220\ seeks 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 authorities and transmission
operators to notify others through pre-determined communication paths
of any condition that could threaten the reliability of their areas or
when firm load shedding is anticipated.
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\220\ In its November 15, 2006, filing, NERC submitted COM-002-
2, which supercedes the Version 1 Reliability Standard. COM-002-2
adds Measures and Levels of Non-Compliance to the Version 1
Reliability Standard. In this Final Rule, we review the November
version, COM-002-2.
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511. The Commission proposed in the NOPR to approve Reliability
Standard COM-002-1 as mandatory and enforceable. In addition, the
Commission proposed 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 balancing authorities; (3) includes distribution providers
as applicable entities and (4) requires tightened communications
protocols, especially for communications during alerts and emergencies.
With respect to this final issue, the Commission proposed alternatively
to direct NERC to develop a new Reliability Standard that responds to
Blackout Report Recommendation No. 26, which deals with the need for
tightened communications protocols.
i. Applicability to Distribution Providers
(a) Comments
512. While EEI states that there is a clear need to apply the
Reliability Standard to distribution providers, APPA finds the proposal
problematic because it would mean that close to 2,000 public power
systems would have to be added to the compliance registry. APPA argues
that the Commission should instruct NERC to consider the applicability
of COM-002-2 to distribution providers through its Reliability
Standards development process. MRO requests that the Commission clarify
whether the distribution providers will continue to operate their own
systems in the future.
(b) Commission Determination
513. The Commission finds that, during both normal and emergency
operations, it is essential that the transmission operator, balancing
authority and reliability coordinator have communications with
distribution providers. In response to APPA, as discussed above, any
distribution provider that is not a user, owner or operator of the
Bulk-Power System would not be required to comply with COM-002-2, even
though the Commission is requiring the ERO to modify the Reliability
Standard to include distribution providers as applicable entities.
APPA's concern that 2,000 public power systems would have to be added
to the compliance registry is misplaced, since, as we explain in our
Applicability discussion above, we are approving NERC's registry
process, including the registry criteria. Therefore, we adopt our
proposal to require the ERO to modify COM-002-2 to apply to
distribution providers through its Reliability Standards development
process.
514. The Commission believes that this Reliability Standard does
not alter who would operate a distribution provider's system. It only
concerns communications, not the operation of the distribution system.
ii. Measures and Levels of Non-Compliance
(a) Comments
515. APPA notes that the Levels of Non-Compliance for COM-002-2 are
inadequate in two respects: (1) reliability coordinators are not
included in any Level of Non-Compliance and (2) the Levels of Non-
Compliance for transmission operators and balancing authorities in
Compliance D.2 do not reference Requirements R1 and R2. Therefore, APPA
would support approval of COM-002-2 as a mandatory Reliability
Standard, but would not support levying penalties for violating
incomplete portions of the Reliability Standard.
(b) Commission Determination
516. As stated in the Common Issues section, a Reliability Standard
is enforceable even if it does not contain Levels of Non-
Compliance.\221\ However, the Commission agrees with APPA that this
Reliability Standard could be improved by incorporating the changes
proposed by APPA. Therefore, when reviewing the Reliability Standard
through the Reliability Standards development process, the ERO should
consider APPA's concerns.
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\221\ See Common Issues Pertaining to Reliability Standards:
Measures and Levels of Non-Compliance, supra section II.E.2.
---------------------------------------------------------------------------
iii. Reliability Coordinator Assessment and Approval of Actions that
have Impacts Beyond the Area Views of Transmission Operators and
Balancing Authorities
(a) Comments
517. Alcoa argues that there is a need for communication regarding
operating actions taken by transmission operators and balancing
authorities that may have impacts beyond their area views. However, a
number of commenters oppose the Commission's proposal to modify the
Reliability Standard to require reliability coordinators to assess and
approve actions that have impacts
[[Page 16471]]
beyond the area views of transmission operators or balancing
authorities and seek clarifications.\222\ Alcoa, California PUC, SDG&E
and Xcel are concerned that obtaining approval from reliability
coordinators could create delays in completing the operating action in
emergency situations. Xcel and Alcoa request that the Commission
clarify that this requirement would not prevent timely performance by a
transmission operator of actions necessary to maintain the reliability
of its system under emergency conditions.\223\ Both Alcoa and Xcel are
concerned that waiting for an assessment and approval by a reliability
coordinator may not be feasible, especially during emergencies. Xcel
further asks the Commission to clarify that the entity taking operating
actions should not be held responsible for delays caused by the
reliability coordinator's assessment and approval. Alcoa suggests that
there should be a clear definition of what actions have an impact
beyond the area views of transmission operators or balancing
authorities. SDG&E further states that serious damage to transmission
equipment could occur if the transmission operator is not able to take
immediate action during an emergency.
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\222\ See, e.g., APPA, EEI, California PUC, ISO-NE and SDG&E.
\223\ Alcoa notes that this is consistent with the Requirements
in TOP-001-1, which provides transmission operators and balancing
authorities wide latitude to preserve reliability of their area.
---------------------------------------------------------------------------
518. ISO-NE is concerned that the Commission proposal goes too far
and if implemented, will prevent capable transmission operators from
quickly addressing reliability problems that may arise. It maintains
that transmission operators usually do not have enough time to inform
the reliability coordinator, who must then ``assess and approve'' the
proposed action. If the Commission's proposal is implemented,
transmission operators will doubt themselves and delay necessary
action. However, it does not see any problem for the New England
balancing area and the NPCC region, because ISO-NE serves as the New
England reliability coordinator, balancing authority and transmission
operator.
519. APPA contends that the Commission's proposed directive appears
to have been covered under Reliability Standard IRO-005-1. EEI agrees,
stating that IRO-005-1 already requires a reliability coordinator to
ensure that transmission operators and balancing authorities operate to
prevent action or non-action that will impact neighboring areas.\224\
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\224\ The Requirement R13 of IRO-005-1 provides that ``[e]ach
reliability coordinator shall ensure that Transmission Operators,
Balancing Authorities * * * operate to prevent the likelihood that a
disturbance, action or non-action in its Reliability Coordinator
Area will result in a SOL or IROL violation in another area of the
Interconnection.''
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(b) Commission Determination
520. The Commission reaffirms its belief that Reliable Operation of
the Bulk-Power System can only be achieved by coordinated efforts of
all operating entities, such as reliability coordinators, transmission
operators and balancing authorities in operating their respective
systems and performing their respective functions in accordance with
their responsibilities and authorities. Most operating actions taken by
transmission operators and balancing authorities in real-time would
only affect their own areas and equipment and have no adverse impacts
on the interconnection reliability operating limits, and therefore they
have unilateral authority to act. However some operating actions that
would have impacts beyond their own areas must involve the reliability
coordinator who has the wide-area views and the necessary operating
tools, including monitoring facilities and real-time analytic tools
with wide-area representation to enable the reliability coordinator to
fulfill its responsibility.\225\ In response to Alcoa, the Commission
believes that actions that have an impact beyond an area will, in
general, vary based on the conditions at the time of the action.
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\225\ The NERC glossary states that A 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 and procedures, including the authority
to prevent or mitigate emergency operating situations in both next-
day analysis and real-time operations. The reliability coordinator
has the purview that is broad enough to enable the calculation of
IROLs, which may be based on the operating parameters of
transmission systems beyond any transmission operator's vision.''
NERC Glossary at 15.
---------------------------------------------------------------------------
521. Further, we clarify that we did not propose to require an
entity to inform its reliability coordinator of every action it takes.
Instead, the proposed directive included a Requirement for the
reliability coordinator to assess and approve only those actions that
have impacts beyond the area views of transmission operators and
balancing authorities. We remain convinced that it is the reliability
coordinator's responsibility to ensure Reliable Operation of its
reliability coordinator area. The reliability coordinator must also
ensure that actions taken by operating entities under its authority
will not have wide-area impacts that would adversely impact Reliable
Operation of the Bulk-Power System. Therefore, we adopt the proposed
directive as stated in the NOPR.
522. In response to commenters, the Commission clarifies that the
proposed directive does not conflict with the transmission operators'
and balancing authorities' rights to take actions necessary to preserve
reliability of their areas and alleviate operating emergencies,
consistent with Requirement R1 and R2 in TOP-001-1.\226\ Further, the
proposed directive does not in any way diminish their operating
authority regarding local area reliability for normal and emergency
situations, a responsibility that is under the responsibility of a
transmission operator or a balancing authority. However, the majority
of their operating actions are not emergency actions and would only
affect a transmission operator's or balancing authority's area of
responsibilities. Since these actions are expected to have little
impact outside of the transmission operator's or balancing authority's
area, the authority to take unilateral actions remains with the
transmission operator or balancing authority. Other non-emergency
actions should be coordinated with the reliability coordinator prior to
taking action.
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\226\ TOP-001-1, R1 states in part ``Each transmission operator
shall have the responsibility and clear decision-making authority to
take whatever actions are needed to ensure the reliability of its
area * * * '' and R2 states in part ``Each transmission operator
shall take immediate actions to alleviate operating emergencies * *
*.''
---------------------------------------------------------------------------
523. Regarding SDG&E's concern that serious damage to transmission
equipment could occur if the transmission operator is not able to take
immediate action during an emergency, we believe this is adequately
addressed under Requirement R3 of TOP-001-0 which provides that
operating entities need not comply with directives from reliability
coordinators when such actions would violate safety, equipment,
regulatory or statutory requirements.
524. NERC should consider Xcel's suggestion that the entity taking
operating actions should not be held responsible for delays caused by
the reliability coordinator's assessment and approval in the
Reliability Standards development process. We note that the operating
entity has the authority to take emergency actions to protect its
system that may circumvent or preempt the reliability coordinator's
approval process under TOP-001-1 Requirement R3 in cases of personnel
safety, potential equipment failure or environmental needs.
525. We disagree with commenters that the Commission's proposed
[[Page 16472]]
directive is already covered under Requirement R13 of IRO-005-1, which
requires each reliability coordinator to ensure that all transmission
operators, balancing authorities and others operate to prevent the
likelihood that a disturbance, action, or non-action in its reliability
coordinator area will result in a SOL and IROL violation in another
area of the Interconnection. In order for the reliability coordinator
to carry out its function under IRO-005-1, it must have information
from the transmission operators and balancing authorities. However,
IRO-005-1 does not require transmission operators and balancing
authorities to provide the reliability coordinator with the information
it would need to prevent the likelihood that an action from these two
entities will result in a SOL or IROL violation in another area of the
Interconnection. The Commission's directive ensures that the
reliability coordinator has such information. Therefore, we do not
believe that COM-002-2 is duplicative of IRO-005-1.
526. Accordingly, we direct the ERO to include a Requirement for
the reliability coordinator to assess and approve actions that have
impacts beyond the area views of transmission operators or balancing
authorities, including how to determine whether an action needs to be
assessed by the reliability coordinator. This Requirement is best
developed under the Reliability Standards development process including
the consideration whether this Requirement should be included in this
communications Reliability Standard or an operating Reliability
Standard.
iv. Tightened Communications Protocols
527. The Blackout Report cited ineffective communications as a
factor common to the August 14, 2003 blackout and other previous major
outages in North America.\227\ In addition, Recommendation No. 26 of
the Blackout Report instructed NERC, working with reliability
coordinators and control area operators, to ``[t]ighten communications
protocols, especially for communications during alerts and emergencies
* * * ''.\228\ In the NOPR, the Commission endorsed Blackout
Recommendation No. 26 and proposed to direct the ERO to require
tightened communications protocols, especially for communications
during alerts and emergencies. Alternatively, we proposed to direct the
ERO to develop a new Reliability Standard that responds to the Blackout
Report Recommendation.
---------------------------------------------------------------------------
\227\ Blackout Report at 107.
\228\ Id. at 141.
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(a) Comments
528. In its response to the Staff Preliminary Assessment, NERC
agreed with the need to develop additional Reliability Standards
addressing consistent communications protocols among personnel
responsible for the reliability of the Bulk-Power System.\229\
---------------------------------------------------------------------------
\229\ NOPR at P 255.
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529. EEI supports the Commission in its concerns regarding Blackout
Recommendation No. 26 on emergency communications. However, EEI states
that Requirement R4 of EOP-001-0, Emergency Operations Planning,
addresses the Commission's concerns about communication protocols
during emergency conditions.\230\ EEI recommends that, instead of
duplicating the same requirement in COM-002-2, the Commission should
consider directing NERC to provide an interpretation on the elements of
such protocols.
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\230\ EOP-001-0, Requirement R4 provides, in relevant part,
that: ``[e]ach Transmission Operator and Balancing Authority shall
have emergency plans that will enable it to mitigate operating
emergencies. At a minimum, Transmission Operator and Balancing
Authority emergency plan shall include [c]ommunication protocols to
be used during emergencies.''
---------------------------------------------------------------------------
530. APPA believes that the communications protocols to be used
during emergencies should be included in the relevant Reliability
Standard that governs each type of emergency, rather than in COM-002-2.
For example, Requirement R3 of Reliability Standard VAR-002-1
establishes the protocol for communication with the transmission
operator if a generator loses its ability to provide voltage control.
By keeping the necessary communication protocols clustered with the
events to which they apply, NERC would make the Reliability Standards
more user-friendly.
531. MISO claims that Blackout Report Recommendation No. 26 on
tightened communications protocols dealt primarily with NERC
infrastructure and has been fully implemented. It is concerned that
developing measures that require ongoing administration will impede
rather than improve timely communications in an emergency.
(b) Commission Determination
532. We adopt our proposal to require the ERO to establish
tightened communication protocols, especially for communications during
alerts and emergencies, either as part of COM-002-2 or as a new
Reliability Standard. We note that the ERO's response to the Staff
Preliminary Assessment supports the need to develop additional
Reliability Standards addressing consistent communications protocols
among personnel responsible for the reliability of the Bulk-Power
System.
533. While we agree with EEI that EOP-001-0, Requirement R4.1
requires communications protocols to be used during emergencies, we
believe, and the ERO agrees, that the communications protocols need to
be tightened to ensure Reliable Operation of the Bulk-Power System. We
also believe an integral component in tightening the protocols is to
establish communication uniformity as much as practical on a continent-
wide basis. This will eliminate possible ambiguities in communications
during normal, alert and emergency conditions. This is important
because the Bulk-Power System is so tightly interconnected that system
impacts often cross several operating entities' areas.
534. Regarding APPA's suggestion that it may be beneficial to
include communication protocols in the relevant Reliability Standard
that governs those types of emergencies, we direct that it be addressed
in the Reliability Standards development process.
535. In response to MISO's contention that Blackout Report
Recommendation No. 26 has been fully implemented, we note that
Recommendation No. 26 addressed two matters. We believe MISO is
referring to the second part of the recommendation requiring NERC to
``[u]pgrade communication system hardware where appropriate'' instead
of tightening communications protocols. While we commend the ERO for
taking appropriate action in upgrading its NERCNet, we remind the
industry to continue their efforts in addressing the first part of
Blackout Recommendation No. 26.
536. Accordingly, we direct the ERO to either modify COM-002-2 or
develop a new Reliability Standard that requires tightened
communications protocols, especially for communications during alerts
and emergencies.
v. Other Issues
(a) Comments
537. Santa Clara requests clarification whether the phrase ``Such
communications shall be staffed and available'' in Requirement R1
applies only to operating staff available on site at all times or
includes repair personnel who are available only on an on-call basis.
538. FirstEnergy asks that the Reliability Standard specify what is
[[Page 16473]]
meant by ``staffed'' and states that the term should not require a
physical presence at all facilities at all times because some units,
such as peaking units, are not staffed 24 hours a day. In addition,
FirstEnergy suggests that, because nuclear units are already subject to
communications requirements in their operating procedures, their
compliance with NRC operating procedures should be deemed in compliance
with the NERC Reliability Standards.
539. Similarly, Six Cities states that, to avoid unnecessary
staffing burdens, particularly for smaller entities, the Commission
should direct NERC to clarify COM-002-2 by providing that
identification of an emergency contact person on call to respond to
real-time emergency conditions will constitute adequate compliance.
(b) Commission Determination
540. Santa Clara, FirstEnergy and Six Cities suggest specific new
improvements to the Reliability Standards. As stated above, such
comments should be considered as the ERO modifies the Reliability
Standards in the Reliability Standards development process.
vi. Summary of Commission Determination
541. While the Commission identified concerns regarding COM-002-2,
the proposed Reliability Standard serves an important purpose by
requiring users, owners and operators to implement the necessary
communications and coordination among entities. Accordingly, the
Commission approves Reliability Standard COM-002-2 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 directs the ERO to
develop a modification to COM-002-2 through the Reliability Standards
development process that: (1) Expands the applicability to include
distribution providers as applicable entities; (2) includes a new
Requirement for the reliability coordinator to assess and approve
actions that have impacts beyond the area view of a transmission
operator or balancing authority \231\ and (3) requires tightened
communications protocols, especially for communications during alerts
and emergencies. Alternatively, with respect to this final issue, the
ERO may develop a new Reliability Standard that responds to Blackout
Report Recommendation No. 26 in the manner described above. Finally, we
direct the ERO to include APPA's suggestions to complete the Measures
and Levels of Non-Compliance in its modification of COM-002-2 through
the Reliability Standards development process.
---------------------------------------------------------------------------
\231\ This Requirement could, for example, be included in COM-
002-2 or in an operating Reliability Standard.
---------------------------------------------------------------------------
4. EOP: Emergency Preparedness and Operations
542. 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.
a. Emergency Operations Planning (EOP-001-0)
543. 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.
544. In the NOPR, the Commission proposed 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,
the Commission proposed 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.
545. Most of the comments address the specific modifications and
concerns raised by the Commission in the NOPR. Below, we address each
topic separately, followed by an over-all conclusion and summary.
i. Applicability to reliability coordinators
(a) Comments
546. MRO states that it is necessary to include reliability
coordinators as applicable entities because reliability coordinators
have a wide-area view. FirstEnergy also supports making the proposed
Reliability Standard applicable to the reliability coordinator.
FirstEnergy states the reliability coordinator should take an active
role and should have clearly defined, specific responsibilities for
coordinating and implementing emergency operations plans. In addition,
FirstEnergy states that inclusion of the reliability coordinator as an
applicable entity removes ambiguity that may exist concerning the
reliability coordinator's role and its responsibilities during
restoration activities.
547. SoCal Edison agrees that certain aspects of EOP-001-0 should
be applicable to reliability coordinators; however, it proposes that
NERC, through the stakeholder process, should receive input from
stakeholders on which requirements should be exclusive to the
transmission operator or balancing authority with the reliability
coordinator responsible only for collecting and incorporating this
information into its overarching plan. MISO, on the other hand,
questions the need for the proposed modification, contending that the
reliability coordinators have parallel responsibilities laid out in
other EOP Reliability Standards.
(b) Commission Determination
548. In the NOPR, we stated that the proposed Reliability Standard
applies to transmission operators and balancing authorities, that the
applicability portion of the Reliability Standard is sufficiently clear
as to who must comply with the filed version of the Reliability
Standard and that the Reliability Standard can be enforced against
these entities.\232\ However, we recognized commenters' concerns that
the Reliability Standard does not assign a role to the reliability
coordinator, which is the highest level of authority responsible for
reliable operation of the Bulk-Power System and which has a wide-area
view. MISO contends that EOP-001-0 need not apply to reliability
coordinators because they have parallel responsibilities in other EOP
Reliability Standards. We disagree. Given the importance NERC
attributes to the reliability coordinator in connection with matters
covered by EOP-001-0, the Commission is persuaded that specific
responsibilities for the reliability coordinator in the development and
coordination of emergency plans must be included as part of this
Reliability Standard. While balancing authorities and transmission
operators are capable of developing, maintaining and implementing plans
to mitigate
[[Page 16474]]
operating emergencies for their specific areas of responsibility,
unlike reliability coordinators, they do not have wide-area views.
---------------------------------------------------------------------------
\232\ NOPR at P 272.
---------------------------------------------------------------------------
549. Further we agree with SoCal Edison that clear direction is
needed on which requirements should be exclusive to transmission
operators and balancing authorities with the reliability coordinator
being responsible for incorporating this information into its
overarching plan. Accordingly, the Commission finds the reliability
coordinator is a necessary entity under EOP-001-0 and directs the ERO
to modify the Reliability Standard to include the reliability
coordinator as an applicable entity. In addition, the ERO should
consider SoCal Edison's suggestion in the ERO's Reliability Standards
development process.
ii. Clarification of the 30-minute Load Shedding Requirement
(a) Comments
550. NERC comments that the proposed directive to clarify the 30-
minute requirement in Requirement R2 presumes that all manual load
shedding can be performed by supervisory control. It states that, in
many systems, shedding load requires actions by field personnel who
must be dispatched to a site. NERC recognizes the reliability benefit
of being able to shed greater amounts of load in seconds or minutes but
contends that the amount of load shedding under remote supervisory
control and the timing requirements should be vetted through industry
experts based on good utility practice. While acknowledging that the
proposed modification is appropriate because it corresponds to current
good utility practice and widely held interpretations of the
requirement to shed load, FirstEnergy, like NERC, notes that loads that
does not have SCADA cannot be shed within 30 minutes because field
staff must be dispatched. It proposes that the Reliability Standard
should specify that, for loads that do not have SCADA, the
implementation plan must be initiated, but not necessarily completed,
within 30 minutes. Similarly, MidAmerican is concerned that if load
shedding is to be performed in much less than 30 minutes it will
require automatic load shedding which may trigger when not required
leading to less reliability under certain conditions. MidAmerican
proposes a modification to specifically permit load shedding with non-
automatic schemes.
551. Xcel states that the proposed modification is unnecessary
because there are many different options besides load shedding that
could be implemented to alleviate IROL violations within 30 minutes. It
adds that load shedding is the option of last resort and that the
timing for implementation of load shedding would be better addressed in
proposed Reliability Standard EOP-003-1. EEI and California PUC state
that not all load reduction schemes should be required to be operable
within 30 minutes; only those used for emergency operations. APPA
states that the 30-minute interval was selected based on industry
consensus and, rather than dismiss this consensus, the Commission
should instruct NERC to reconsider the 30-minute requirement and either
modify it or better explain why it is the appropriate time period for
the requirement. MISO questions what would be achieved by the proposed
modification and states that operators do not intentionally delay
taking action when required.
552. International Transmission and PG&E state that shedding load
``as soon as possible and much less than 30 minutes'' is vague and
unenforceable. International Transmission proposes shedding of load
``as soon as possible when required to mitigate an IROL violation, but
in no case in more than 30 minutes.''
(b) Commission Determination
553. The proposed Reliability Standard states that the transmission
operator shall have an emergency load reduction plan for all identified
IROLs and that the load reduction plan must be capable of being
implemented within 30 minutes. In the NOPR, we proposed to direct NERC
to modify EOP-001-0 to clarify the 30-minute requirement in Requirement
R2 to state that load shedding should be capable of being implemented
as soon as possible and in much less than 30 minutes.\233\ The intent
was to have a requirement that precludes waiting until the 29th minute
to begin implementation.
---------------------------------------------------------------------------
\233\ Id. at P 273.
---------------------------------------------------------------------------
554. In response to the concerns of commenters, the Commission
clarifies that the proposed modification does not require that SCADA or
its equivalent be installed for all loads. Rather, SCADA would be
required only for those loads necessary to mitigate IROL violations and
to maintain reliable operations. As we stated in the NOPR, the
Commission understands that it is not the intent of the Reliability
Standard to require the shedding of all available load within 30
minutes, but rather only the amount necessary to correct system
emergencies.\234\ Thus the Commission agrees with EEI and California
PUC that not all load reduction schemes should be required to be
operable within 30 minutes but only those used for emergency
operations.
---------------------------------------------------------------------------
\234\ Id.
---------------------------------------------------------------------------
555. Further, as Xcel recognizes, load shedding is the option of
last resort and there may be other options available to alleviate IROL
violations within 30 minutes. The ERO should consider these other
options as it works through the Reliability Standards development
process to modify EOP-001-0.
556. With regard to the wording of the proposed modification
stating that load shedding should be capable of being implemented ``as
soon as possible and in much less than 30 minutes,'' the Commission
agrees with PG&E and International Transmission that this language may
be unclear and unduly subjective. In the NOPR, we stated that the
reference to 30 minutes could suggest that anything up to that limit
was acceptable and proposed the modification to emphasize our concern
that implementation was expected much sooner than in 30 minutes.
International Transmission's suggested rewording addresses our concern.
Accordingly, we direct the ERO to develop a modification through the
Reliability Standards development process clarifying that when the load
reduction plan of Requirement R2 involves load shedding, such load
shedding be capable of being implemented as soon as possible when
required to mitigate an IROL violation but in no case in more than 30
minutes.
557. Finally, in response to APPA's comments, as stated in the
NOPR,\235\ the Commission accepts the 30-minute requirement as a
reasonable period within which operators should return the system to a
reliable operating state. However, in order to satisfy this
Requirement, when load shedding is the only viable option, the
Commission believes that operators must have the capability through
SCADA or other equivalent means to shed appropriate amounts of load in
the desired locations as soon as possible to mitigate IROL violations
but in no case in more than 30 minutes.\236\
---------------------------------------------------------------------------
\235\ Id. at P 995.
\236\ Id.
---------------------------------------------------------------------------
iii. Definitions of System States
(a) Comments
558. FirstEnergy states that it may be difficult to define system
states that cover all operating conditions, but nonetheless recognizes
that the standardization of these states is a first step to bringing
clarity to operators concerning system conditions and the
[[Page 16475]]
resulting actions they are expected to take. California PUC, on the
other hand, states that imposing uniform definitions for ``normal,''
``alert'' and ``emergency'' states is impractical and
counterproductive. California PUC claims that trying to define in
advance all contingencies that the system may face is probably
infeasible and argues that improved real-time monitoring of the grid is
the preferred approach for quick identification and correction of
problems.
559. ISO-NE states that it is important to define system states but
that such definitions should not be implemented until a ``pilot
program'' is field tested. ISO-NE explains that after such a pilot
program is conducted operators would need to make changes to their
policies and procedures, including operator training, to make sure that
their practices are administered in a secure and well-understood
fashion.
(b) Commission Determination
560. In the NOPR, the Commission stated that clearly defined system
states incorporated into real-time operation can significantly improve
operator recognition of emergency conditions, rapid and accurate
response and recovery to normal system conditions.\237\
---------------------------------------------------------------------------
\237\ Id. at P 275.
---------------------------------------------------------------------------
561. The Commission recognizes that the triggering events and the
nature of the emergency states may be different for different systems;
however, we find that a clearly defined set of system states will help
operators proactively avert escalations of system disturbances and
cascading outages. Further, operators, the ERO and regulators will
better understand how reliably the system is operating and how it
performed historically if statistics can be collected based on well-
defined system states. We find it reasonable for the ERO, through the
stakeholder process, to develop a well-defined set of uniform,
continent-wide system states that can be understood by transmission
operators, balancing authorities, reliability coordinators and the ERO
to correspond to specific, predetermined levels of urgency.
562. As we noted in the NOPR, some control areas define and
effectively use more than the ``normal,'' ``alert'' and ``emergency''
system states included in the Blackout Report recommendation.\238\ We
proposed that the ERO determine the optimum number of system states to
be employed continent-wide and to consider the addition of the
restoration state.\239\ Accordingly, we direct the ERO to determine the
optimum number of continent-wide system states and their attributes and
to modify the Reliability Standard through the Reliability Standards
development process to accomplish this objective.
---------------------------------------------------------------------------
\238\ Id. at P 276.
\239\ Id.
---------------------------------------------------------------------------
563. Further, we agree with ISO-NE that the proposed modification
should be field-tested and that policies and procedure be put in place,
including operator training, before any processes for continent-wide
system states are implemented. Such testing will help assure that all
applicable entities and their personnel understand how the terms will
be used and will allow operators to train staff to make any necessary
changes to their policies and procedures. We direct the ERO to consider
such a pilot program as it modifies EOP-001-0 through the Reliability
Standards development process.
iv. Other issues
(a) Comments
564. ISO-NE raises two additional concerns with the proposed
Reliability Standard. First, it states that activities outlined in
Requirement R7.4, including coordinating fuel conservation and
arranging for fuel deliveries, are not functions that independent
transmission operators and balancing authorities typically perform.
Second, ISO-NE notes that Requirement R5 provides that each
transmission operator and balancing authority must include applicable
elements of Attachment 1 of EOP-001-0 in an emergency plan. However,
according to ISO-NE, the elements identified in Attachment 1 are
characterized as ``for consideration'' and are not mandatory. ISO-NE
argues that the proposed Reliability Standard should be clarified to
indicate that the actual emergency plan elements, and not the ``for
consideration'' elements of Attachment 1, should be the basis for
compliance.
(b) Commission Determination
565. With regard to ISO-NE's concern that certain activities
outlined in Requirement R7.4 are not functions normally performed by
independent transmission operators and balancing authorities, the
Commission understands that this Requirement covers either delivery of
fuel or delivery of electrical energy from remote systems. While
arranging for fuel deliveries may be outside of the functions that ISOs
and RTOs perform, the requirement to arrange deliveries of electrical
energy from remote systems is a function they normally perform. Because
an ISO or RTO may choose to either deliver fuel or electrical energy
from remote systems, Requirement R7.4 will not burden ISOs and RTOs
with functions they do not normally perform.
566. The Commission agrees with ISO-NE that the Reliability
Standard should be clarified to indicate that the actual emergency plan
elements, and not the ``for consideration'' elements of Attachment 1,
should be the basis for compliance. However, all of the elements should
be considered when the emergency plan is put together.
v. Summary of Commission Determination
567. Accordingly, the Commission concludes that Reliability
Standard EOP-001-0 is just, reasonable, not unduly discriminatory or
preferential and in the public interest and approves it 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 directs the ERO to
develop a modification to EOP-001-0 through the Reliability Standards
development process 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 but in no more than 30 minutes;
(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 and (4)
clarifies that the actual emergency plan elements, and not the ``for
consideration'' elements of Attachment 1, should be the basis for
compliance. Further, the Commission directs the ERO to consider a pilot
program for system states, as discussed above.
b. Capacity and Energy Emergencies (EOP-002-2)
568. EOP-002-2 applies to balancing authorities and reliability
coordinators and is intended to ensure that they are prepared for
capacity and energy emergencies.\240\ The Reliability Standard requires
that balancing authorities have the authority to bring
[[Page 16476]]
all necessary generation on line, communicate about the energy and
capacity emergency with the reliability coordinator and coordinate with
other balancing authorities. EOP-002-2 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 LSE.
---------------------------------------------------------------------------
\240\ In its November 15, 2006, filing, NERC submitted EOP-002-
2, which supercedes the Version 1 Reliability Standard. EOP-002-2
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, EOP-002-2.
---------------------------------------------------------------------------
569. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed to direct that NERC submit a
modification to the Reliability Standard 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 DSM in Requirement R6 as one
possible remedy that a balancing authority may use to bring it in
compliance with control performance and disturbance control Reliability
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.
570. Most of the comments address the specific modifications and
concerns raised by the Commission in the NOPR. Below, we address each
topic separately, followed by an over-all conclusion and summary.
i. Insufficient Transmission Capability
(a) Comments
571. MRO believes that the definition for the term ``insufficient
transmission capability'' should be clarified because insufficient
transmission capability could be due to a thin spot in the
interconnection, prior outages or storm damage.
(b) Commission Determination
572. As we stated in the NOPR, neither EOP-002-2 nor any other
Reliability Standard addresses the impact of inadequate transmission
during generation emergencies.\241\ The Commission agrees with MRO that
``insufficient transmission capability'' could be due to various
causes. The ERO should examine whether to clarify this term in the
Reliability Standards development process.
---------------------------------------------------------------------------
\241\ NOPR at P 284.
---------------------------------------------------------------------------
ii. Demand-Side Management
(a) Comments
573. FirstEnergy states that it is appropriate to include demand-
side resources as another tool for balancing authorities to use in
meeting control performance and disturbance control Reliability
Standards. It states, however, that in order to qualify, the demand-
side resource options must meet similar technical requirements as
generation resource options. Comverge recommends that the terms
``demand response'' and ``curtailable loads'' be specifically added to
R3, R4 and R6.3 and Alert Level 1 to ensure that they are included in
the list of resources that will be controlled during capacity and
energy emergencies. APPA contends that Requirement R6.6 adequately
accounts for the use of demand-side remedies to address emergencies. As
such, APPA opposes the Commission's proposal as being unduly
prescriptive. Also ISO-NE contends that the proposed modifications
effectively dictate a specific means to solve the underlying problems
instead of leaving it to the responsible entities to determine how to
achieve the reliability objective. A proper recommendation would be to
make the requirement resource-neutral.
(b) Commission Determination
574. The Commission agrees with FirstEnergy that for demand-side
resources to qualify as another tool for balancing authorities to use
in meeting control performance and disturbance control Reliabilty
Standards, they must meet comparable technical performance requirements
as generation resource options. In response to comments from Comverge
and APPA, the Commission believes that curtailable loads are adequately
addressed in Requirement R6 of the Reliability Standard but that demand
response is not covered.\242\ Demand response covers considerably more
resources than interruptible load. Accordingly, the Commission directs
the ERO to modify the Reliability Standard to include all technically
feasible resource options in the management of emergencies. These
options should include generation resources, demand response resources
and other technologies that meet comparable technical performance
requirements.
iii. Warning regarding TLR procedure
---------------------------------------------------------------------------
\242\ Requirement R6 provides, in pertinent part: ``R6. If the
Balancing Authority cannot comply with the Control Performance and
Disturbance Control Standards, then it shall immediately implement
remedies to do so. These remedies include, but are not limited to:
R6.3. Interrupting interruptible load and exports.''
---------------------------------------------------------------------------
(a) Comments
575. MRO states that it is very important that all concerned
parties realize that TLR is not a first line of defense to mitigate
IROL violations. Entergy and MidAmerican agree that TLR procedures are
not effective to mitigate IROL violations or for use in emergency
situations. EEI supports the Commission's proposed modifications to the
Reliability Standard; however, EEI along with Entergy, MidAmerican and
APPA, believes that the TLR process is effective in avoiding and
mitigating potential IROL violations. These commenters request that the
Commission clarify the proposed modification so that it does not
foreclose such use of the TLR process.
576. International Transmission states that TLR can be an effective
and appropriate means to mitigate IROL violations or for use in
emergency situations and therefore EOP-002-2 should not preclude the
use of TLR when its use is warranted. MISO states that, while TLR is
not the preferred method of responding to emergencies, an operator
should not be precluded from implementing TLR during emergencies. It
argues that TLR may be appropriate when events develop slowly or when
an entity is affected by external transactions and has exhausted all
control actions or needs to reserve some control actions for
contingencies.
577. APPA contends that the specific direction provided in this
proposed modification intrudes on NERC's role as a standard setting
agency and would be better framed as a direction to NERC to investigate
the concern and revise the Reliability Standard accordingly. Similarly,
while ISO-NE supports the Commission's conclusion that reliance on TLR
procedures can be inappropriate, it recommends that the proposed
Reliability Standard would be improved if it did not specify the
operating method required to achieve compliance. ISO-NE also believes
that the Commission should direct NERC to allow the responsible
entities flexibility in the means by which they achieve compliance with
the Reliability Standard.\243\
---------------------------------------------------------------------------
\243\ ISO-NE also notes that in the first line of Requirement R7
the reference to ``R7'' should be to ``R6.''
---------------------------------------------------------------------------
(b) Commission Determination
578. A number of commenters agree that the TLR procedure is an
inappropriate and ineffective tool for mitigating actual IROL
violations or for
[[Page 16477]]
use in emergency situations.\244\ On the other hand, International
Transmission believes the TLR procedure can be an appropriate and
effective tool to mitigate IROL violations or for use in emergency
situations and MISO argues that operators should not be precluded from
implementing the TLR procedure during emergencies. The Commission
disagrees. As explained in the NOPR and in the Blackout Report, actions
undertaken under the TLR procedure 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. As such the Commission cannot
agree with International Transmission and MISO. However, the Commission
agrees with APPA, EEI, Entergy and MidAmerican that the TLR procedure
may be appropriate and effective for use in managing potential IROL
violations. Accordingly, the Commission will maintain its direction
that the ERO modify the Reliability Standard to ensure that the TLR
procedure is not used to mitigate actual IROL violations.
---------------------------------------------------------------------------
\244\ See, e.g., APPA, EEI, Entergy and MidAmerican.
---------------------------------------------------------------------------
579. As to APPA's comment that we are intruding on NERC's role as a
standard-setting agency, we have authority to direct the ERO to submit
a modification and, in this instance, requiring the ERO to
``investigate the concern'' first is unnecessary. The issue is
narrowly-framed and the comments identify no points requiring the
approach suggested by APPA. In response to ISO-NE, we are precluding
use of TLR procedures at times of actual IROL violations, but are not
otherwise specifying permissible responses.
iv. Other issues
580. ISO-NE states that Requirement R2 essentially requires the
same actions covered by ISO-NE Operating Procedure No. 4. ISO-NE is
concerned that a strict approach to auditing compliance with the
Reliability Standard could result in a finding that ISO-NE was in
violation of the Reliability Standard if it skipped a particular action
under its emergency plan even though that action was not called for
under ISO-NE procedures. ISO-NE requests that the Commission direct
NERC to clarify that a system operator has discretion not to implement
every action specified in its capacity and energy emergency plans when
other appropriate actions are possible.
581. FirstEnergy claims that Requirement R1 may impose overlapping
obligations and authority on reliability coordinators and balancing
authorities who may have the same, partial or whole footprint and who
are both likely to respond to the same emergency.
582. APPA notes that revised Reliability Standard EOP-002-2, filed
by NERC on November 15, 2006, includes new Measures for some of the
requirements but not all the requirements. APPA states that NERC should
be directed to include Measures related to Requirements R4, R5, R6, R7
and R9.1.
(a) Commission Determination
583. The Commission finds that the issues raised by ISO[dash]NE
should be addressed through the Reliability Standards development
process. As to FirstEnergy's concern with Requirement R1, the
reliability coordinator has the highest level of authority.
Accordingly, the Commission directs that the ERO, through the
Reliability Standards development process, address ISO[dash]NE's
concern. Further, we direct the ERO to consider adding Measures and
Levels of Non-Compliance in the Reliability Standard.
v. Summary of Commission Determination
584. Accordingly, the Commission approves Reliability Standard EOP-
002-2 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 directs the ERO to develop a modification to EOP-002-2
through the Reliability Standards development process that: (1)
Addresses emergencies resulting not only from insufficient generation
but also from insufficient transmission capability particularly where
this affects the implementation of the capacity and energy emergency
plan; (2) includes all technically feasible resource options, including
demand response and generation resources, in the management of
emergencies and (3) ensures that the TLR procedure is not used to
mitigate actual IROL violations.
c. Load Shedding Plans (EOP-003-1)
585. EOP-003-1 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.\245\ It 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.
---------------------------------------------------------------------------
\245\ In its November 15, 2006, filing, NERC submitted EOP-003-
1, which supercedes the Version 0 Reliability Standard. EOP-003-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, EOP-003-1.
---------------------------------------------------------------------------
586. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed 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.
587. Most of the comments address the specific modifications and
concerns raised by the Commission in the NOPR. Below, we address each
topic separately, followed by an over-all conclusion and summary.
i. Minimum load shedding and maximum delay
(a) Comments
588. FirstEnergy and APPA agree that NERC should modify EOP-003-1
to specify the minimum load shedding capability and the maximum amount
of delay. However, FirstEnergy adds that Requirement R8, which states
that load shedding actions must be taken in a ``time frame adequate for
responding to the emergency,'' is ambiguous and difficult to
substantiate. NERC acknowledges that significant improvements can be
made to the EOP Reliability Standards to establish criteria for the
provision of load shedding capability, but it states that requiring a
specific minimum amount of load (MW) or percentage of load that must be
capable of being shed and the maximum amount of time delay is as likely
to reduce reliability as it is to increase it. NERC contends that the
electric characteristics of local systems and loads must be considered
in designing manual and automatic load shedding capabilities.
Accordingly, it proposes that the Commission direct NERC to review
industry best practices and propose requirements in the Reliability
Standards to ensure that adequate load shedding capabilities are
provided to protect the Bulk-Power System without causing adverse
impacts associated with unnecessary shedding of firm load.
[[Page 16478]]
589. SoCal Edison states that in certain circumstances, but not in
all cases, it would be valuable to have a minimum limit established for
the amount of load shedding an entity is to accomplish. It suggests
that the specific requirements should be derived based on studied
conditions.
590. Xcel, ISO-NE, TVA and International Transmission do not
support a nationwide Reliability Standard for minimum load shedding and
maximum delay for implementing load shedding because there are large
variations in load, resources and system configuration and
characteristics across the continent. TVA states that these parameters
should be determined based on studies of the specific transmission
systems and applicable contingency events. MISO states that it is not
clear what is intended or achieved by this requirement because
balancing authorities and transmission operators should already have
the ability to shed, by some means, all load within their area and the
timing requirements are specified in the IROL-related Reliability
Standards.
591. California PUC is concerned that the proposed modification
assumes that load shedding at the transmission level is the only or the
primary way to address system emergencies. SDG&E recommends that the
maximum delay for shedding load should begin when the transmission
operator or balancing authority has actual knowledge of the
circumstances that would precipitate load shedding.
(b) Commission Determination
592. Shedding of firm load is an operating measure of last resort
to contain system emergencies and prevent cascading. System operators
must have the capability to shed load in a timely manner to return the
system to a stable condition. The Commission disagrees with NERC's
contention that requiring a specific minimum amount of load that must
be capable of being shed and the maximum amount of delay is as likely
to reduce reliability as it is to increase it. As stated in the NOPR,
the actual amount of load to be shed, the location and the time frame
will be at the discretion of the system operator based on the nature of
the system problem and the operator's assessment of corrective actions
required.\246\ 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.
---------------------------------------------------------------------------
\246\ NOPR at P 294.
---------------------------------------------------------------------------
593. While the Reliability Standard requires transmission operators
and balancing authorities to be capable of load shedding in a time
frame adequate for responding to emergencies, this could be clearer, as
noted by FirstEnergy. As mentioned by NERC, significant improvements
can be made to the Reliability Standard to establish criteria for the
provision of load shedding capability. We agree.
594. Several commenters state that they do not support a nationwide
Reliability Standard for minimum load shedding capability and maximum
delay in implementing load shedding because these parameters are
dependent on system configurations and load and resource
characteristics across the continent, and as such, must be determined
based on system studies.\247\ The Commission agrees that the minimum
load shedding capability must take into account system characteristics
and topology, however the maximum time delay before load shedding can
be implemented is independent of system characteristics and is governed
by what is considered to be feasible.
---------------------------------------------------------------------------
\247\ See Xcel, ISO-NE, TVA, International Transmission and
MISO.
---------------------------------------------------------------------------
595. California PUC is concerned that the proposed modification on
load shedding assumes that load shedding at the transmission level is
the only or preferred way to address system emergencies. The Commission
clarifies that this assumption is incorrect and agrees with California
PUC that load shedding at the distribution level has the minimum
societal and economic impact.
596. The Commission concludes that the Reliability Standard needs
to be modified to ensure that adequate load shedding capabilities are
provided so that system operators have an effective operating measure
of last resort to contain system emergencies and prevent cascading. The
Commission recognizes that the amount of load shedding capability
required is dependent on system characteristics and therefore it may
not be feasible to have a uniform nationwide load shedding capability.
This, however, does not preclude a uniform nationwide criterion on the
methodology for establishing load shedding capability that would
specify the minimum amount of load shedding capability that should be
provided based on system characteristics and conditions and the maximum
amount of delay before load shedding can be implemented. The Commission
directs the ERO to address the minimum load and maximum time concerns
of the Commission through the Reliability Standards development
process. We suggest that a review of industry best practices would be
useful in developing nationwide critera.
ii. Periodic drills of simulated load shedding
(a) Comments
597. California PUC states that, since load shedding at the
distribution level has the minimum societal and economic impact, the
Reliability Standard should require all neighboring distribution or
transmission utilities to participate in annual drills when requested
by an ISO or other bulk power authority. Northern Indiana and
FirstEnergy support mandating periodic drills of simulated load
shedding; however, FirstEnergy states that the drill requirements
should include simulated load shed via a simulator or table-top
exercise, not an actual deployment of manpower, and that these drill
requirements should be included in the PER-005-0 Reliability Standard
instead of EOP-003-1. PER-005-0 only involves training of control room
personnel, whereas these drills should also include testing the
readiness and functionality of procedures and personnel outside of the
control room.
(b) Commission Determination
598. As suggested by California PUC, periodic drills of simulated
load shedding should involve all participants required to ensure
successful implementation of load shedding plans. As such, the drills
should extend beyond system operators to distribution operators and
LSEs. The Reliability Standard should require periodic drills by
entities subject to section 215, and require those entities to seek
participation by other entities. The drills should test the readiness
and functionality of the load shedding plans, including, at times, the
actual deployment of personnel. Therefore the Commission disagrees with
FirstEnergy that the requirement for periodic drills of simulated load
shedding should be incorporated into the new PER-005-0 Reliability
Standard that is currently being drafted to address operator training.
iii. Other issues
(a) Comments
599. Santa Clara states that since automatic load shedding for
undervoltage conditions is not required in most parts of the West and
possibly in other areas of the country,
[[Page 16479]]
Requirement R2 should be modified to include the words ``as applicable
per the Regional Reliability Organization.'' In addition, APPA states
that NERC should consider requiring balancing authorities and
transmission operators to expand coordination and planning of their
automatic and manual load shedding plans to include their respective
Regional Entities, reliability coordinators and generation owners.
ISO[dash]NE proposes that NERC establish coordinated trip settings
within and among balancing authorities for each interconnection.
600. While EEI generally supports the proposed modifications, it
believes that the proposal for senior management to post letters to
safeguard operators who shed load in accordance with approved
guidelines does not respond to or meet the needs reflected in the
Blackout Recommendation No. 8. EEI points out that, under other
provisions of the FPA, the Commission has approved liability limiting
provisions for some operators that appears to be consistent with the
Blackout Report Recommendation No. 8, but has rejected other similar
protections. EEI requests that the Commission explicitly state that
transmission operators taking action in compliance with the load
shedding provisions of Commission approved Reliability Standards will
be protected from retaliatory actions, including legal actions.
(b) Commission Determination
601. Regarding Santa Clara's concern that undervoltage load
shedding is not required in most parts of WECC and that Requirement R2
should be modified to reflect this, the Commission notes that
Requirement R2 states that each transmission operator and balancing
authority shall establish plans for automatic load shedding for
underfrequency or undervolatge conditions. The Commission clarifies
that the Reliability Standard does not mandate undervoltage load
shedding unless needed for Reliable Operation.
602. We also note that APPA and ISO[dash]NE raise issues regarding
coordination of trip settings and automatic and manual load shedding
plans. The Commission directs the ERO to consider these comments in
future modification to the Reliability Standard through the Reliability
Standards development process.
603. EEI seeks adoption of a provision to shield transmission
operators from liability when they take action in compliance with the
load shedding provisions of the Reliability Standards. Consistent with
our discussion of Blackout Report Recommendation No. 8 in the Common
Issues section of this Final Rule, the Commission will not adopt new
liability protections.\248\ According to the Task Force, no further
action is needed to implement that recommendation because some states
already have appropriate protection against liability suits.\249\
Further, in Order No. 890, we have already declined to provide a
uniform federal liability standard.
---------------------------------------------------------------------------
\248\ See Common Issues Pertaining to Reliability Standards:
Blackout Report Recommendation on Liability Limitations, supra
section II.E.1.
\249\ U.S.-Canada Power System Outage Task Force, Final Report
on Implementation of Task Force Recommendations at 22 (Oct. 3,
2006), available at http://www.oe.energy.gov/news/blackout.htm (``In
the United States, some state regulators have informally expressed
the view that there is appropriate protection against liability
suits for parties who shed load according to approved guidelines.'')
---------------------------------------------------------------------------
iv. Summary of Commission Determination
604. The Commission approves proposed Reliability Standard EOP-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 directs the ERO to develop a modification to EOP-003-1
through the Reliability Standards development process that: (1)
Includes a requirement to develop specific minimum load shedding
capability that should be provided and the maximum amount of delay
before load shedding can be implemented based on an overarching
criteria that take into account system characteristics and (2) requires
periodic drills of simulated load shedding.
d. Disturbance Reporting (EOP-004-1)
605. EOP-004-1 establishes requirements for reporting system
disturbances to the regional reliability organization and the ERO.\250\
It also establishes requirements for the analysis of these
disturbances.
---------------------------------------------------------------------------
\250\ In its November 15, 2006, filing, NERC submitted EOP-004-
1, which supercedes the Version 0 Reliability Standard. EOP-004-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, EOP-004-1.
---------------------------------------------------------------------------
606. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed to direct that NERC submit a
modification to the Reliability Standard 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.
i. Comments
607. EEI and FirstEnergy support the Commission's proposed
modifications to the Reliability Standard. EEI states that data
reporting requirements and other process requirements should be
contained in enforceable Reliability Standards. FirstEnergy states that
the proposed modification corresponds to good utility practice and that
explicitly stating the requirement to provide data to NERC brings
clarity to the expectations of NERC and the Commission.
608. APPA is concerned about the scope of Requirement R2 because,
in its opinion, Requirement R2 appears to impose an open-ended
obligation on entities such as generation operators and LSEs that may
have neither the data nor the tools to promptly analyze disturbances
that could have originated elsewhere. APPA proposes that Requirement R2
be modified to require affected entities to promptly begin analyses to
ensure timely reporting to NERC and DOE.
609. Xcel expresses concern regarding what constitutes a reportable
event for each applicable entity and recommends that the Reliability
Standard be revised to define what a reportable event is for each
entity that has reporting obligations. Further, Xcel states that the
requirement in Requirement R3.4 for a final report within 60 days may
not be feasible given the current WECC process, which among other
things, requires the creation of a group to prepare the report and a
30-day posting of a draft report before it becomes final. Xcel also
states that if the ultimate purpose of the report is to provide
information to avoid a recurrence of a system disturbance, then the
Reliability Standard should be revised to require the distribution of
the report to similarly situated entities.
610. FirstEnergy states that, since nuclear units have their own
NRC reporting procedures covering the Requirements under EOP-004-1, the
Reliability Standard should specify that compliance with such operating
procedures is sufficient to satisfy the requirements of EOP-004-1.
FirstEnergy also states that the title of this Reliability Standard
should be changed to ``Disturbance Event Reporting'' to indicate that
the events covered under this Reliability Standard include a broad
range of events that go beyond the events for which reports may be
required under Reliability Standard BAL-002-0.
[[Page 16480]]
611. APPA states that NERC's November 15, 2006 revision partially
fulfills the proposed modification to include Measures and Levels of
Non-Compliance. APPA notes that EOP-004-1 did not provide Measures for
R2, R3.2, R3.4, R4 and R5.
ii. Commission Determination
612. Complete and timely data is essential for analyzing system
disturbances. In the NOPR, the Commission proposed modifying this
disturbance Reporting Standard to include requirements necessary for
users, owners and operators of the Bulk-Power System to provide
disturbance data, voice recordings and other information collected
during the disturbance to assist NERC in the investigation of the
blackout or disturbance.\251\ While some commenters agree with this
proposal, APPA and Xcel express concerns regarding the scope and
applicability of some of the Requirements of the Reliability Standard.
---------------------------------------------------------------------------
\251\ NOPR at P 304.
---------------------------------------------------------------------------
613. Requirement R2 of the Reliability Standard requires
reliability coordinators, balancing authorities, transmission
operators, generator operators and LSEs to promptly analyze
disturbances on their system or facilities. APPA is concerned that
generator operators and LSEs may be unable to promptly analyze
disturbances, particularly those disturbances that may have originated
outside of their systems, as they may have neither the data nor the
tools required for such analysis. The Commission understands APPA's
concern and believes that, at a minimum, generator operators and LSEs
should analyze the performance of their equipment and provide the data
and information on their equipment to assist others with their
analyses. The Commission directs the ERO to consider this concern in
future revisions to the Reliability Standard through the Reliability
Standards development process.
614. The Commission disagrees with Xcel that the Reliability
Standard is unclear about what constitutes a reportable event.
Attachment 1 of the Reliability Standard details the various events
that would trigger the reporting requirement under this Reliability
Standard.
615. FirstEnergy states that since nuclear units have their own NRC
reporting requirements the Reliability Standard should specify that
compliance with NRC procedures is sufficient to satisfy the obligations
of this Reliability Standard. The Commission disagrees with FirstEnergy
because there are situations where the ERO Reliability Standards are
more stringent than the NRC procedures. In such cases, the ERO
Reliability Standards must apply in addition to the NRC requirements.
Also, the Commission disagrees with FirstEnergy's comment on changing
this Reliability Standard's name to avoid confusion with BAL-002-0. The
purpose of the Reliability Standard is clear as to the extent of the
disturbances to be reported.
616. The Commission declines to address Xcel's concerns about the
current WECC process. These issues should be addressed in the
Reliability Standards development process or submitted as a regional
difference. The Commission directs the ERO to consider all comments in
future modifications of the Reliability Standard through the
Reliability Standards development process.
617. In response to APPA's concern that NERC did not provide a
Measure for each Requirement, we reiterate that it is in the ERO's
discretion whether each Requirement requires a corresponding Measure.
The ERO should consider this issue through the Reliability Standards
development process.
618. While the Commission has identified concerns with regard to
EOP-004-1, we believe that the proposal serves an important purpose in
establishing requirements for reporting and analysis of system
disturbances. Accordingly, the Commission approves Reliability Standard
EOP-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 directs the ERO to develop a modification to EOP-004-1
through the Reliability Standards development process that 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.
619. Requirement R3 addresses the reporting of disturbances to the
regional reliability organizations and NERC. The Commission directs the
ERO to change its Rules of Procedure to assure that the Commission also
receives these reports within the same time frames as DOE.
e. System Restoration Plans (EOP-005-1)
620. EOP-005-1 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.
621. In the NOPR, the Commission proposed to approve Reliability
Standard EOP-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 proposed 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.
i. Comments
622. APPA and EEI state that Reliability Standard EOP-005-1 is
sufficient for approval as a mandatory Reliability Standard and
requests that the Commission direct NERC to address missing Measures
and training requirements. In addition, APPA notes that the Reliability
Standard is applicable to both balancing authorities and transmission
operators but the Measures and Levels of Non-Compliance elements refer
only to transmission operators.
623. ISO[dash]NE does not support adoption of the proposed
Reliability Standard because, while Requirement R1 requires
transmission operators to include applicable elements from Attachment 1
of EOP-005-1 in their restoration plans, Requirement R1 appears to
indicate that the elements in Attachment 1 are to be included in the
emergency plan only ``as applicable.'' ISO[dash]NE states that the
Reliability Standard should be clarified to indicate that the actual
emergency plan elements should be the basis for compliance.
624. EEI and FirstEnergy note that the proposed modification to
identify time frames for training and review of restoration plan
requirements is being addressed in the proposed Reliability Standard
PER-005-1 and that including this requirement in EOP-005-1 would be
redundant. MISO also believes that the proposed modification is
unnecessary. It states that there are already requirements for
simulation-based training on emergencies and restoration and it is
unclear what is meant by conducting training to prepare operators for
unforeseen events.
[[Page 16481]]
625. FirstEnergy states that Requirement R1 calls for a plan for a
partial shutdown of the system and that there is an infinite set of
events that can cause a partial shutdown. According to FirstEnergy,
because the borders of a partial shutdown are difficult, if not
impossible, to foresee, the Reliability Standard should specify some
boundaries for analysis of partial shutdowns including an appropriate
definition of the term ``partial shutdown.'' In addition, FirstEnergy
states that one uniform plan for all systems is not feasible; rather
the Reliability Standard should recognize that some companies already
have existing plans that could be used for analyzing events.
FirstEnergy also states that the Reliability Standard should provide a
uniform checklist of factors to analyze, developed on a company-
specific basis.
626. NRC suggests that this Reliability Standard include: (1) A
requirement to record the time it takes to restore power to the
auxiliary power systems of nuclear power plants; (2) a provision
stating that the affected transmission operators shall give high
priority to restoration of off-site power to nuclear power plants
whether or not a nuclear power plant is being powered from the nuclear
power plant's onsite power supply and (3) a provision stating that
restoration shall not violate nuclear power plant minimum voltage and
frequency requirements.
627. While not commenting on the substance of Reliability Standard
EOP-005-1, MRO states that EOP-005-1, EOP-006-1 and EOP-007-0 are
ordered in a confusing manner and should be renumbered. MRO reasons
that since the regional coordinator has oversight responsibility for
system restoration, EOP-006-1 should be first in the system restoration
sequence of Reliability Standards (i.e., EOP-006-1 should precede EOP-
005-1). Further, MRO recommends that EOP-005-1 follow EOP-006-1 because
transmission owners and balancing authorities are responsible for
submitting restoration plans to the regional coordinator. MRO requests
that if a reason exists for the current order, NERC should provide that
reason to the Commission.
ii. Commission Determination
628. With regard to comments that the Commission's concerns are
being addressed in NERC's drafting of proposed PER-005-1 Reliability
Standard on operator training, we note PER-005-1 only includes
Requirements on the control room personnel and not those outside of the
control room. System restoration requires the participation of not only
control room personnel but also those outside of the control room.
These include blackstart unit operators and field switching operators
in situations where SCADA capability is unavailable. As such, the
Commission believes that inclusion of periodic system restoration
drills and training and review of restoration plans in a system
restoration Reliability Standard is the most effective way of achieving
the desired goal of ensuring that all participants are trained in
system restoration and that the restoration plans are up to date to
deal with system changes.
629. Several commenters raise issues that should be addressed by
the ERO through the Reliability Standards development process.\252\ For
example: whether the Measures and Levels of Non-Compliance should refer
to balancing authorities; clarification of the elements that form the
basis for compliance with the requirements of Attachment 1; what
constitutes a partial shutdown for which restoration plans must be
developed and recognition that some companies already have existing
plans that could be used for analyzing events; and that the Reliability
Standard should provide a uniform checklist of factors to analyze,
developed on a company-specific basis. We find that consideration of
these issues could be helpful in meeting the objectives of the
Reliability Standard. Accordingly, the ERO should consider these
concerns in future revisions of the Reliability Standard through the
Reliability Standards development process.
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\252\ See APPA, ISO-NE, FirstEnergy and MRO.
---------------------------------------------------------------------------
630. NRC raises several issues concerning the role and priority
that nuclear power plants should have in system restorations. The
Commission shares these concerns and directs the ERO to consider the
issues raised by NRC in future revisions of the Reliability Standard
through the Reliability Standards development process. In addition the
Commission directs the ERO to gather data, pursuant to Sec. 39.5(f) of
the Commission's regulations, from simulations and drills of system
restoration on the time it takes to restore power to the auxiliary
power systems of nuclear power plants under its data gathering
authority and report that information to the Commission on a quarterly
basis.
631. We find that the Reliability Standard adequately addresses
operating personnel training and system restoration plans to ensure
that transmission operators, balancing authorities and reliability
coordinators are prepared to restore the Interconnection following a
blackout. Accordingly, the Commission approves Reliability Standard
EOP-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 directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies
time frames for training and review of restoration plan requirements to
simulate contingencies and prepare operators for anticipated and
unforeseen events and gathers the data from simulations and drills of
system restoration on the time it takes to restore power to the
auxiliary power systems of nuclear power plants under its data
gathering authority and report that information to the Commission on a
quarterly basis.
f. Reliability Coordination-System Restoration (EOP-006-1)
632. Proposed Reliability Standard EOP-006-1 addresses reliability
coordination and system restoration.\253\ 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.
---------------------------------------------------------------------------
\253\ In its November 15, 2006, filing, NERC submitted EOP-006-
1, which supercedes the Version 0 Reliability Standard. EOP-006-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, EOP-006-1.
---------------------------------------------------------------------------
633. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed to direct that NERC submit a
modification to the Reliability Standard that: (1) requires that the
reliability coordinator be involved in the development of and approves
restoration plans and (2) includes Measures and Levels of Non-
Compliance.
i. Comments
634. APPA states that Reliability Standard EOP-006-1, which NERC
filed on November 15, 2006, includes the required Measures and Levels
of Non-Compliance and as such APPA agrees that EOP-006-1 should be
approved as mandatory and enforceable. In addition, APPA does not
oppose industry consideration of a requirement that reliability
coordinators be involved in the development and approval of restoration
plans.
[[Page 16482]]
635. EEI states that Requirements R4 and R11 of EOP-005-1 already
address reliability coordinator involvement in the development and
approval of transmission operator system restoration plans. Further,
while EEI agrees that the reliability coordinator's role is
appropriate, it believes that the asset owner, as the entity that
ultimately bears responsibility for restoration capabilities, should
also have authority to develop and maintain the plans. MISO believes
that it is unnecessary to modify the Reliability Standard to involve
the reliability coordinator because there is already a requirement in
EOP-005-1 for balancing authorities and transmission operators to
coordinate their plans with the reliability coordinator.
636. Xcel disagrees that the reliability coordinator should be
involved with the development of restoration plans because the
reliability coordinator typically does not have the knowledge of the
details necessary to develop the plans in contrast to the balancing
authorities and the transmission operators. Instead it proposes that
the reliability coordinator develop its own plans and coordinate that
with the balancing authority and transmission operator's plans.
ii. Commission Determination
637. The reliability coordinator is the highest level of authority
that is responsible for the reliable operation of the Bulk-Power
System. Given the importance of this role in connection with matters
covered by EOP-006-1, the Commission believes that the reliability
coordinator must be involved in the development and approval of the
restoration plans. The current Reliability Standard only requires that
the reliability coordinator be aware of the restoration plan of each
transmission operator in its area. The Commission disagrees with EEI
and MISO, who contend that the reliability coordinator's role in the
transmission operator's restoration plan is covered in EOP-005-1. EOP-
005-1 only requires coordination with the reliability coordinator, and
during actual system restoration, EOP-005-1 requires approval from the
reliability coordinator to resynchronize isolated areas with other
isolated areas.
638. In response to comments by Xcel, the Commission believes that
while the reliability coordinator may not have the level of detailed
knowledge that the balancing authorities and transmission operators may
have for setting-up the stable islands required under restoration
plans, the reliability coordinator is in the best position to determine
how those stable islands should be resynchronized with each other and
the rest of the interconnected system.
639. The Commission finds that the Reliability Standard adequately
addresses the goals of effective and efficient reliability coordination
and system restoration. Accordingly, the Commission approves
Reliability Standard EOP-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 directs the ERO to develop a
modification to EOP-006-1 through the Reliability Standards development
process that ensures that the reliability coordinator, which is the
highest level of authority responsible for reliability of the Bulk-
Power System, is involved in the development and approval of system
restoration plans.
g. Establish, Maintain, and Document a Regional Blackstart Capability
Plan (EOP-007-0)
640. 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.
641. The NOPR did not propose to approve or remand EOP-007-0,
because it applies only to regional reliability organizations.
i. Comments
642. APPA agrees that EOP-007-0 should not be approved as a
mandatory Reliability Standard and states that in the interim the
regional reliability organizations and Regional Entities should
continue to perform this function. In addition, APPA proposes that, in
the interim, an umbrella organization composed of representatives from
each regional reliability organization and Regional Entity should be
formed to establish operation planning rules, including blackstart
requirements, across the Eastern Interconnection. APPA suggests that
such an effort would go a long way in identifying critical facilities,
using consistent and transparent study assumptions and minimizing seams
during system emergencies throughout the Interconnection.
643. TANC states that the number of blackstart units and their
locations depend heavily on regional characteristics and cannot be
prescribed in a uniform, continent-wide manner. It proposes that
regional flexibility be afforded to provide an appropriate mix of
facilities to achieve the reliability objectives. EEI suggests that
EOP-007-0 be rewritten so that compliance obligations are assigned
directly to those entities that provide the data and other information.
644. FirstEnergy and MRO state that the reliability coordinator,
not the Regional Entity, should be responsible for the regional
blackstart plan for its area of responsibility. Further, FirstEnergy
states that the blackstart plan developed for a region should be
consistent with NRC requirements, should recognize that nuclear units
have no blackstart capability and should recognize that nuclear units
must have priority access to off-site power for safety reasons.
FirstEnergy requests that the Commission direct NERC to revise the
definition of a blackstart unit to mean a ``diesel, hydro, pump
storage, or the combustion turbine generating unit that is used to
provide cranking power to a larger steam generating unit designed to
restore load'' or to mean a ``larger steam generating unit designed to
restore load.'' \254\ MRO states that arrangements for coordination of
blackstart capability should be addressed in a contract between
appropriate entities.
---------------------------------------------------------------------------
\254\ See FirstEnergy at 35.
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ii. Commission Determination
645. The Commission will not approve or remand EOP-007-0, because
it applies only to regional reliability organizations. However, the
Commission provides guidance for the ERO's future consideration.
646. The Commission disagrees with APPA that an umbrella
organization is needed for the Eastern Interconnection while the
Reliability Standard is pending final approval. The Commission is
persuaded that FirstEnergy's and MRO's comments concerning the
reliability coordinator being responsible for regional blackstart plans
have merit. The Commission has directed that the reliability
coordinator approve the system restoration plans and this is a logical
extension of that direction. However, until such time as the
Reliability Standard has been revised and approved by the ERO and the
Commission, the regional reliability organization (or Regional Entity,
depending on the organization of a particular region) should continue
to perform this role as it has in the past.\255\
---------------------------------------------------------------------------
\255\ See NOPR at P 328.
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647. With regard to TANC's request for regional flexibility in
determining the appropriate mix of facilities needed to achieve the
reliability objectives, it is
[[Page 16483]]
our understanding that the Reliability Standard provides for the number
and location of blackstart units to vary depending on the specific
requirements of each system. We believe that uniformity will be
required, however, in the criteria used to determine the number and
location of blackstart units and testing requirements.
648. EEI, FirstEnergy and MRO offer suggestions for improving the
Reliability Standard. The Commission directs the ERO to consider these
suggestions in future revisions to improve EOP-007-0, through the
Reliability Standards development process.
649. Accordingly, the Commission will not approve or remand EOP-
007-0 at this time.
h. Plans for Loss of Control Center Functionality (EOP-008-0)
650. EOP-008-0 addresses plans for loss of control center
functionality. It requires each reliability coordinator, transmission
operator and balancing authority to have a plan to continue reliable
operations and to maintain situational awareness in the event its
control center is no longer operable.
651. The Commission proposed five modifications to the Reliability
Standard and requested additional comments on other issues. We have
grouped the comments into two general categories: (1) Capabilities of
backup control centers and (2) which entities should have full backup
centers. Below, we address each topic separately, followed by an
overall conclusion and summary.
i. Capabilities of Backup Control Centers
652. In the NOPR, the Commission proposed 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,
the Commission proposed to direct that NERC submit a modification to
EOP-008-0 that includes a Requirement that provides for backup
capabilities that, 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.\256\ In addition to these three capabilities
requirements, the Commission solicited comments concerning other
specific capabilities.
---------------------------------------------------------------------------
\256\ The term ``facility'' in this context includes, but is not
limited to, telecommunications, backup power supplies, computer
systems and security systems. NOPR at P 335 & n.159.
---------------------------------------------------------------------------
(a) Comments
653. EEI, Entergy, FirstEnergy and Northern Indiana support the
proposed modifications to EOP-008-0. Entergy agrees with the
Commission's proposed modifications to include more Requirements
regarding backup capabilities.
654. APPA, Nevada Companies and TAPS caution that costs must be
considered and compared to possible benefits. APPA states that it would
take some time to implement the proposed modifications and therefore
specific requirements for backup control facilities and capabilities
should be left to the Reliability Standard development process. Nevada
Companies cautions that utilities that have invested millions of
dollars in back-up capabilities may find these facilities to be non-
compliant with the proposed Reliability Standard. It suggests that
cost/benefits analyses be conducted and that a grandfathering provision
be adopted to protect investments in backup systems that were made in a
good faith effort to comply with rules in place in the past, but which
may not comply with the Reliability Standard.
655. MRO requests clarification of the term ``capability'' because
it is unsure if the term is intended to refer to a facility, what such
a facility should consist of and what operators should be capable of
doing from that facility.
656. In response to the request for comments on backup
capabilities, NERC states that these are best addressed through the
Reliability Standards development process.
657. SoCal Edison suggests that a risk-based assessment be
considered to determine the requirements for backup. MISO, TAPS and
International Transmission note that work is underway by NERC to
address the provisions for redundancy and backup control capabilities
via the Operating Committee Backup Control Task Force and that the
focus is on functionality rather than physical requirements. TAPS
states that, rather than directing NERC to adopt specific modifications
to the Reliability Standard that would inappropriately burden small
systems with the cost of dual facilities, the Commission should
identify objectives to the Task Force. TAPS also states that a small
balancing authority might be able to meet the functional requirements
for a backup control center with a contract with another entity while
larger entities might need a physical backup center.
658. Northern Indiana states that the Commission's proposal appears
to eliminate an entity's opportunity to contract for backup
capabilities from others who already have full backup control centers.
FirstEnergy and Northern Indiana advocate for flexibility in the means
used to meet the backup requirements and request that the Commission
clarify that a ``full backup center'' can include providing full
redundancy by contract rather than physical backup center facilities.
SoCal Edison states that when entities utilize the services of another
entity for backup, they should be required to test the backup
capability a minimum number of times during the year and that all
system operators should be required to participate in such testing over
a specified time period.
659. NRC suggests that this Reliability Standard require: (1) A
list of the nuclear power plants and their voltage, thermal, and/or
frequency limits and (2) provisions to notify nuclear power plants of
the loss of control center functionality.
(b) Commission Determination
660. As we stated in the NOPR, the goal of the Reliability Standard
is the continuation of reliable operations and the maintenance of
situational awareness in the event that the primary control center is
no longer operational.\257\ Some commenters support the proposal to
require backup capabilities while others including APPA, Nevada
Companies and TAPS caution that the cost of the proposal may not be
justified. In addition, some commenters, including FirstEnergy and
Northern Indiana, advocate for flexibility in meeting the backup
requirements and suggest that entities should be able to contract for
full redundancy. MRO seeks clarification regarding the use of the term
``capability.''
---------------------------------------------------------------------------
\257\ NOPR at P 329.
---------------------------------------------------------------------------
661. In the NOPR, we found that the provision of backup
capabilities should be an explicit Requirement to meet the objectives
of the Reliability Standard. We chose to use the word ``capabilities''
to avoid defining particular facilities or preclude other options,
including arranging for backup capabilities by contracting with others.
We stated that the mechanism to provide these capabilities may include
building fully redundant physical backup control centers, contracting
for backup control services or using backup equipment within a separate
existing facility.\258\ In addition, regardless of the means used to
provide the backup capabilities, as we stated in the NOPR, the time
period for which backup capability is required
[[Page 16484]]
should correspond to the time it would take to replace the primary
control center.
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\258\ See Id. at P 336.
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662. On the issue of additional backup capabilities, NERC, MISO,
TAPS and International Transmission propose that the functional
requirements for backup capabilities be determined by the NERC Backup
Control Task Force. NRC offers requirements it believes should be added
to the Reliability Standard.
663. The Commission disagrees with the Nevada Companies' proposal
for grandfathering. The Reliability Standards must define the minimum
functions that are necessary for the Reliable Operation of the Bulk-
Power System. The flexibility described above on how capabilities are
provided should mitigate any costs incurred to upgrade older centers.
664. Given the importance to reliability of maintaining situational
awareness in the event of loss of the primary control center
operations, the Commission believes that, at a minimum, the three
requirements--independence from the primary control center, capability
to operate for a prolonged period corresponding to the time it would
take to replace the primary control center, and the provision of a
minimum set of tools and facilities to replicate the critical
reliability functions of the primary control center--must be included
as explicit requirements in the Reliability Standard. Other additional
Requirements may be developed by the Backup Control Task Force for
inclusion in the Reliability Standard. The Commission directs the ERO
to develop modifications to the requirements in future revisions to the
Reliability Standard through the Reliability Standards development
process.
ii. Which entities should have full backup centers
665. In the NOPR , the Commission proposed to direct that NERC
submit a modification to EOP-008-0 that: (1) Provides 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 and (2) includes a Requirement that all reliability
coordinators have full backup control centers. The Commission also
requested comments on what other entities, such as balancing
authorities and large transmission operators, should have full backup
centers.
(a) Comments
666. International Transmission, MISO and FirstEnergy state that in
addition to reliability coordinators, large balancing authorities and
transmission operators need full backup control centers. MISO states
that there are certain situations where large generation fleets that
are controlled centrally would also warrant full backup systems and
that small entities can operate reliably with less robust systems.
Further, it argues that the ERO needs latitude to decide from a
reliability standpoint how much redundancy is needed. FirstEnergy
states that in place of full backup control facilities it should be
acceptable to have standing contracts in place to provide backup
services in the event of a loss of a control center.
667. NERC states that the proposed directive presumes that the only
way to achieve highly reliable and independent backup capability to
perform reliability coordinator functions in an emergency is to have a
redundant control center. NERC contends that while this may be an
option, it may not be the only one for achieving the necessary
reliability objective. NERC proposes that the Reliability Standard be
modified to define the performance results expected rather than how an
entity should meet the requirements.
668. NERC, SoCal Edison and Otter Tail state that the question of
what other entities should have full backup centers is best addressed
through the Reliability Standards development process. Otter Tail
requests that the Commission not require all balancing authorities to
have full backup centers since the loss of a small balancing
authority's control center would not have a substantial impact on the
reliability of the Bulk-Power System. Northern Indiana states that
requiring transmission operators and balancing authorities to have full
backup centers would result in significant unnecessary facility
duplication, at great cost to consumers, and without a material
increase in reliability.
669. FirstEnergy comments that the Reliability Standard should not
require a fully redundant SCADA system for the backup control center
for balancing authorities or transmission operators because the cost
would be prohibitive. It states that balancing authorities,
transmission operators and centrally-located generation owners should
be permitted to have a single distributed computer system in place to
diminish the probability of a complete system shutdown due to a natural
disaster or a single man-made physical act of sabotage.
670. Nevada Companies also questions whether the significant cost
of full replication could ever be cost-effective, especially
considering the very high level of control center reliability achieved
now with the existing solution of a single control center plus backup
of critical systems.
(b) Commission Determination
671. Several commenters agree with the Commission that reliability
coordinators at a minimum should have full backup control centers. They
also propose that this requirement be extended to large balancing
authorities, transmission operators and centrally dispatched generation
facilities. Others caution on the cost implications of requiring full
duplication given the very high level of control center reliability
achieved with the existing technology and backup of critical systems.
Having carefully considered all the issues raised by commenters and
taking into account the reliability impacts of loss of primary control
centers and the role of reliability coordinators as the highest level
of authority responsible for reliability of the Bulk-Power System, the
Commission is persuaded that all reliability coordinators must have
fully redundant independent backup control centers. In response to
NERC, any proposed modification that is independent from the primary
center, provides for continuous monitoring and has the full
functionality of the primary center would satisfy our concerns. Other
entities, including balancing authorities, transmission operators and
centrally dispatched generation control centers, must provide for the
minimum backup capabilities discussed above but may do so through other
means, such as contracting for these services instead of through
dedicated backup control centers.
672. In addition, in response to FirstEnergy's concern regarding
balancing authorities and transmission operators having fully redundant
SCADA systems and distributed computer systems, the Commission requires
the primary and backup capabilities to replicate critical reliability
functionalities and be independent from the primary control center,
including telemetered data and control from remote terminal units. This
can be achieved through a variety of design alternatives, e.g.,
developing a SCADA management platform that will allow telemetered data
and control to be shared among SCADA systems so that data and control
is not lost during a SCADA or communications failure. The Commission's
focus is on function, not design.
[[Page 16485]]
iii. Summary of Commission Determination
673. Accordingly, the Commission approves Reliability Standard EOP-
0081-0 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 directs the ERO to develop a modification to EOP-008-0
through the Reliability Standards development process that includes a
Requirement that provides for backup capabilities that, at a minimum,
must: (1) Be independent of the primary control center; (2) be capable
of operating for a prolonged period of time, generally defined by the
time it takes to restore the primary control center; (3) provide for a
minimum functionality to replicate the critical reliability functions
of the primary control center; (4) provides 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; (5) includes a Requirement that all reliability coordinators
have full backup control centers and (6) requires transmission
operators and balancing authorities that have operational control over
significant portions of generation and load to have minimum backup
capabilities discussed above but may do so through contracting for
these services instead of through dedicated backup control centers.
i. Documentation of Blackstart Generating Unit Tests Results (EOP-009-
0)
674. Proposed Reliability Standard EOP-009-0 deals with
documentation of blackstart generating unit test results. In the NOPR,
the Commission proposed to approve EOP-009-0 as mandatory and
enforceable without modifications.
i. Comments
675. APPA agrees that EOP-009-0 is sufficient for approval as a
mandatory and enforceable Reliability Standard. Xcel states that the
Reliability Standard should provide details on what constitutes a
blackstart test and FirstEnergy states that EOP-009-0 should be
consolidated with EOP-007-0 because the Requirements of EOP-009-0
already exist in EOP-007-0.
ii. Commission Determination
676. The Commission believes that this Reliability Standard
sufficiently addresses documentation of blackstart generating unit test
results. Accordingly, the Commission approves Reliability Standard EOP-
009-0 as mandatory and enforceable.
677. Two commenters made suggestions for improving the Reliability
Standard. The Commission directs the ERO to take these suggestions into
consideration when revising the Reliability Standard through the
Reliability Standards development process.
5. FAC: Facilities Design, Connections, Maintenance, and Transfer
Capabilities
678. The nine Facility (FAC) Reliability Standards address topics
such as facility connection requirements, facility ratings, system
operating limits and transfer capabilities. The FAC Reliability
Standards also establish requirements for maintaining equipment and
rights-of-way, including vegetation management. The NOPR provided
direction for seven of the nine FAC Reliability Standards; NERC
withdrew two others, Reliability Standards FAC-004-0 and FAC-005-0.
NERC, in its November 15, 2006 filing requests approval of three
additional FAC Reliability Standards: FAC-010-0, FAC-011-0 and FAC-014-
0. These Reliability Standards are being addressed in a separate
docket.
a. Facility Connection Requirements (FAC-001-0)
679. Proposed Reliability Standard FAC-001-0 is intended to ensure
that transmission owners establish facility connection and performance
requirements to avoid adverse impacts to the Bulk-Power System. In the
NOPR, the Commission proposed to approve FAC-001-0 as mandatory and
enforceable.
i. Comments
680. APPA agrees with the Commission's proposal to approve FAC-001-
0 as mandatory and enforceable.
ii. Commission Determination
681. As discussed in the NOPR, the Commission believes that
Reliability Standard FAC-001-0 is just, reasonable, not unduly
discriminatory or preferential and in the public interest and approves
it as mandatory and enforceable.
b. Coordination of Plans for New Generation, Transmission, and End-User
Facilities (FAC-002-0)
682. Proposed Reliability Standard FAC-002-0 requires that each
generation owner, transmission owner, distribution provider, LSE,
transmission planner and planning authority assess the impact of
integrating generation, transmission and end-user facilities into the
interconnected transmission system.
683. In the NOPR, the Commission proposed 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 proposed 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.
i. Applicability and Assessment Responsibility
(a) Comments
684. APPA, Xcel and FirstEnergy state that this Reliability
Standard is not clear about who will perform the required assessment
and how many assessments are required under this Reliability Standard.
APPA requests that the Reliability Standard be clarified to state that
the required assessment must be performed only by the transmission
planner and the planning authority. Xcel requests that the Commission
clarify that only one required assessment needs to be done when new
facilities are added, and that all the listed entities should
participate in that single assessment.
685. FirstEnergy requests that NERC clarify what is considered a
new facility and asks if, for example, up-rates should be included as
new facilities. MRO is concerned that the impact of the Commission's
directive is too broad and may have a substantial affect on those
individual entities that are responsible for performing the studies;
MRO asks the Commission to clarify FAC-002-0 to the extent necessary,
but does not propose a specific change.
686. Six Cities requests that this Reliability Standard clarify
that all applicable entities must make available data necessary for all
other responsible entities to perform the required assessment. Six
Cities also suggests that the transmission operator be added as an
entity to which this Reliability Standard is applicable, at least from
the perspective that it make necessary data available to all other
entities responsible for assessment. TAPS believes that this
Reliability Standard seems to assume that the LSE and distribution
provider actively participate in planning of new facilities in the
Bulk-Power System. TAPS states that very few LSEs or distribution
providers have the expertise to perform the tasks outlined in this
Reliability Standard and that these two entities provide only certain
[[Page 16486]]
data regarding certain new facilities to some or all of the other
entities identified in this Reliability Standard. TAPS therefore
believes that it would be unreasonable to require LSEs to provide the
transmission planning evaluations and assessments called for by R1.
California Cogeneration believes that the Reliability Standard implies
that generator owners will perform an independent assessment and if so,
it believes that such task is impossible, since generators do not have
the relevant information about the power system to perform such
evaluations. California Cogeneration believes that the Reliability
Standard should be clarified so that generator owners cooperate with
and provide input to the assessment performed by the transmission
operator and the balancing authority.
687. FirstEnergy states that both MISO and PJM already have Large
Generator Interconnection Procedures (LGIP) in place that provide a
formal process that meets the requirements listed under R1, and asks
that the Commission state that complying with the interconnection
agreement and/or OATT satisfies this requirement. MISO states that
their procedures for coordinating plans for new generation,
transmission and end-user facilities includes modeling of normal system
and contingency conditions.
(b) Commission Determination
688. All of the above commenters request clarification of
Requirement R1 in the Reliability Standard that states that various
functional entities ``shall each coordinate and cooperate on its
assessments with its transmission planner and planning authority.''
\259\ The Commission believes that all entities listed in the
Applicability section have a stake in the performance of the system and
should have the opportunity to provide input in the assessment under
R1. The Commission believes that commenters have raised valid concerns
that, if addressed, would make the Reliability Standard better. The
wording would allow a number of organizational approaches to achieving
the goal of performing an analysis. The Commission does not intend to
limit which organizational approach is used by the entities, only to
assure that a single competent and collaborative analysis is performed.
Therefore, the Commission directs the ERO to address these concerns in
the Reliability Standards development process.
---------------------------------------------------------------------------
\259\ FAC-002-0.
---------------------------------------------------------------------------
689. FirstEnergy asks the Commission to state that complying with
MISO's and PJM's interconnection agreements and/or OATT satisfies
requirement R1 under this Reliability Standard. We will not make that
determination here. If FirstEnergy believes that complying with the
MISO and PJM interconnection procedures meets the applicable
Reliability Standards, then it should follow those procedures, it
should not be concerned about violating the Reliability Standard.
ii. Standards of Conduct
(a) Comments
690. Xcel and MidAmerican believe that the assessment required
under this Reliability Standard may conflict with the Commission's
Standards of Conduct \260\ since the assessment requires coordination
among several different functional groups within a vertically
integrated public utility. MidAmerican asserts that, since direct
communication between the generation and transmission entities would
result in more efficient overall planning, the Commission should
clarify its intended application of Standards of Conduct restrictions
on joint planning activities. Xcel asks the Commission to clarify that
actions taken to comply with this Reliability Standard will not result
in a transmission provider being in violation of the Standards of
Conduct.
---------------------------------------------------------------------------
\260\ Standards of Conduct for Transmission Providers, Order No.
2004, FERC Stats. & Regs., Regulations Preambles ] 31,155 (2003),
order on reh'g, Order No. 2004-A, III FERC Stats. & Regs. ] 31,161
(2004), order on reh'g, Order No. 2004-B, III FERC Stats & Regs. ]
31,166 (2004).
---------------------------------------------------------------------------
(b) Commission Determination
691. The Commission disagrees with MidAmerican and Xcel that this
Reliability Standard may conflict with the Standards of Conduct. This
type of system assessment is being performed today with the cooperation
of the entities listed in the Applicability section. Further, we note
that the Standards of Conduct were designed to address such
interactions. The entities participating in the assessment effort can
continue to contribute to this assessment and observe the Standards of
Conduct at the same time. If any entity finds an area where it believes
the Standards of Conduct prevent it from cooperating with the
assessment process, it may seek clarification from the Commission as to
whether that area of involvement is in conflict with the Standards of
Conduct.
iii. Reference to TPL Reliability Standards
(a) Comments
692. While APPA and EEI agree with the Commission's proposal to
direct NERC to 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-001-0 through TPL-
003-0, Entergy disagrees and proposes that evaluation of system
performance under Reliability Standards TPL-001-0 and TPL-002-0 should
be sufficient. Entergy states that given the large number of small end-
user requests that transmission operators may receive, expanding the
scope of Requirement R1.4 may lead to additional work and documentation
that ultimately will not benefit reliability. First Entergy states that
the proposed reference to TPL Reliability Standards should be expanded
to include TPL-001-0 through TPL-004-0.
(b) Commission Determination
693. The Commission notes that APPA and EEI agree with the
Commission's proposed directive to NERC to modify FAC-002-0 to require
evaluation of system performance under both normal and contingency
conditions by referencing TPL-001-0 through TPL-003-0. The Commission
also notes that NERC, in response to the Staff Preliminary Assessment,
has also agreed with the same proposal.\261\ These three TPL
Reliability Standards cover normal operation, first contingency
operation and multiple contingency operations respectively. The
Commission disagrees with Entergy that TPL-001-0 and TPL-002-0 are
sufficient because it is important to plan for new facilities taking
into account not only normal circumstances but also contingencies. In
addition, we note that including TPL-001-0 through TPL-003-0 will
result in the FAC-002 Reliability Standard being consistent with Order
No. 2003, which requires interconnecting entities to take into account
multiple contingencies in interconnection studies. With respect to
FirstEnergy's suggestion to also include a reference to Reliability
Standard TPL-004-0, we direct the ERO to consider it through the
Reliability Standards development process.
---------------------------------------------------------------------------
\261\ NOPR at P 352.
---------------------------------------------------------------------------
694. Accordingly, the Commission approves 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 directs the ERO to develop a modification to FAC-002-0
through the Reliability Standards development process that amends
Requirement R1.4 to require evaluation of system performance under both
normal and contingency conditions by referencing TPL-001 through TPL-
003.
[[Page 16487]]
Further, the Commission also directs the ERO to consider the above
commenters' concerns through the Reliability Standards development
process.
c. Transmission Vegetation Management Program (FAC-003-1)
695. According to NERC, 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 establishing a system for uniform reporting of
vegetation-related transmission outages. FAC-003-1 would apply 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). It would require
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.
696. 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 IEEE
Standard 516-2003 (IEEE Guide for Maintenance Methods on Energized
Power Lines).'' \262\
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\262\ FAC-003-1 (Requirement R1.2.2).
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697. In the NOPR, the Commission proposed to approve Reliability
Standard FAC-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 proposed to direct NERC to submit a modification to FAC-
003-1 that: (1) Requires the ERO develop a minimum vegetation
inspection cycle that allows variation for physical differences and (2)
removes the general limitation on 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 on
reliability as determined by the ERO.
i. Applicability
(a) Comments
698. Entergy agrees with the Commission's proposal and supports
applying the Reliability Standard to only those lines that have an
impact on reliability as determined by the ERO, as supported by
reliability studies using consistent reliability contingency criteria.
699. LPPC supports using an impact-based definition of the Bulk-
Power System to determine applicability and suggests that the
definition of significant adverse impact should be determined through
the NERC process. Further, LPPC asserts that actual facilities meeting
that criteria should be determined by Regional Entities, which best
understand the impacts of facilities on the regional system. LPPC notes
that Regional Entities can continue to use such tools as modeling and
power flow analyses to determine which facilities are critical to the
reliability of the Bulk-Power System.
700. APPA and Avista believe that Regional Entities should
determine what transmission facilities this standard applies to, since
Regional Entities have detailed knowledge regarding the transmission
facilities within their regions. APPA would have the Regional Entities
create a regional Reliability Standard to do so, subject to ERO review
for reasonableness and consistency. Avista points out that WECC and the
other Regional Entities have already reviewed and designated critical
lower voltage transmission facilities, and the Reliability Standards
currently apply to such facilities.
701. MISO asks for clarification with respect to the intent of
adding transmission lines below 200 kV ``that impact reliability'' and
whether the included lines are IROL-related facilities \263\ or some
other facilities. Progress and SERC suggest that it may be appropriate
to limit the applicability of the Reliability Standard to all lines
that are operated at 200 kV and above and to operationally significant
circuits between 100 kV and 200 kV that are elements of IROLs.
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\263\ An IROL-related facility is a facility whose outage would
result in an Interconnection Reliability Operating Limit (IROL)
violation.
---------------------------------------------------------------------------
702. California PUC believes that discretion about determining
which lines are critical to the Bulk-Power System should be left to the
individual state (working in concert with RTOs and ISOs), which has
much greater knowledge of what is needed on the local level, rather
than to NERC or the Regional Reliability Organization.
703. Progress, SERC, FirstEnergy and Avista argue that
automatically subjecting lines below 200 kV to Reliability Standard
FAC-003-1 would increase maintenance, documentation and reporting costs
and impacts to land owners, but would not necessarily increase the
reliability of the grid. LPPC does not object to eliminating the 200 kV
bright line threshold, but believes that extending vegetation
management practices to all facilities of 100 kV and above would
unnecessarily extend the scope of the vegetation management
requirements, creating large cost increases for many utilities without
creating a material increase in the reliability of the Bulk-Power
System. FirstEnergy recommends that if the voltage level is lowered,
implementation, especially for reporting requirements, should be spread
over at least one year. Similarly, Xcel asks the Commission to allow
flexibility in complying with this Reliability Standard for lower-
voltage facilities that previously were not subject to this Reliability
Standard.
704. EEI maintains that not changing this Reliability Standard
would best maintain reliability, since removing the existing 200 kV
threshold requirement could inadvertently expose the Bulk-Power System
to a new set of risks. SoCal Edison argues that the Reliability
Standard already covers transmission lines rated less than 200 kV,
because Requirement 4.3 of FAC-003-1 states that this Reliability
Standard ``shall apply 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 the reliability of the electric
system in the region.''
705. APPA opposes the Commission's proposal to direct NERC to
change the applicability of this Reliability Standard. APPA argues that
the Commission should deal with this concern by having NERC reevaluate
the Reliability Standard. National Grid argues that expanding the
applicability of Reliability Standards would not be appropriate because
it could dramatically change the meaning of the Reliability Standards
and would undermine the Reliability Standard development process which
yielded the careful balances struck in developing the standards.
706. NERC argues that the Commission's proposed modification should
be vetted through the Reliability Standards development process to
better understand what will be gained in terms of impacts to the
reliability of the Bulk-Power System. NERC notes that the current
applicability of the Reliability
[[Page 16488]]
Standard to 200 kV and above transmission lines was debated extensively
by the industry, and any change to this requirement should be vetted
again.
(b) Commission Determination
707. We will not direct NERC to submit a modification to the
general limitation on applicability as proposed in the NOPR. However,
we will require the ERO to address the proposed modification through
its Reliability Standards development process. As explained in the
NOPR, 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, none have
designated any operationally significant lines even though there are
lower voltage lines involving IROL as suggested by Progress and SERC.
We continue to be concerned that this approach will not prospectively
result in the inclusion of all transmission lines that could impact
Bulk-Power System reliability. In proposing to require the ERO to
modify the Reliability Standard to apply to Bulk-Power System
transmission lines that have an impact on reliability as determined by
the ERO, we did not intend to make this Reliability Standard applicable
to fewer facilities than it currently is with the 200 kV bright line
applicability, but to extend the applicability to lower-voltage
facilities that have an impact on reliability. We support the
suggestions by Progress Energy, SERC and MISO to limit applicability to
lower voltage lines associated with IROL and these suggestions should
be part of the input to the Reliability Standards development process.
Similarly, the ERO should evaluate the suggestions proposed by LPPC,
APPA and Avista.
708. California PUC suggests that states should have discretion
over what lines are critical to Bulk-Power System reliability. The
Commission has been given the responsibility to approve Reliability
Standards that assure the Reliable Operation of the Bulk-Power System,
including which facilities are covered by the Reliability Standards. We
cannot delegate that responsibility as proposed by California PUC.
Further, since many transmission facilities traverse multiple states,
we are concerned that this proposal could result in the Reliability
Standard applying to a section of a line in one state but not applying
to the same line in a neighboring state. Since a vegetation-related
outage affects all customers connected to that transmission line,
customers in both states could potentially have lower reliability as a
result of one state having a less stringent standard than another.
709. Avista, LPPC, Progress and SERC raise concerns about the cost
of implementing this Reliability Standard if the applicability is
expanded to lower-voltage facilities. We recognize these concerns, and
this was one of the reasons we proposed to apply this Reliability
Standard to Bulk-Power System transmission lines that have an impact on
reliability as determined by the ERO. We recognize that many commenters
would like a more precise definition for the applicability of this
Reliability Standard, and we direct the ERO to develop an acceptable
definition that covers facilities that impact reliability but balances
extending the applicability of this standard against unreasonably
increasing the burden on transmission owners.
710. FirstEnergy and Xcel suggest that if the applicability of this
Reliability Standard is expanded, the Commission should allow
flexibility in complying with this Reliability Standard for lower-
voltage facilities, or allow lower-voltage facilities one year before
the Reliability Standard is implemented. The ERO should consider these
comments when determining when it would request that the modification
of this Reliability Standard to go into effect.
711. In response to EEI's concerns that removing the existing 200
kV threshold could expose the Bulk-Power System to a new set of risks,
we clarify that we are not immediately modifying this Reliability
Standard. Instead, it will go into effect as written and the ERO will
revise it through the Reliability Standards development process, with
the expectation that the applicability of this Reliability Standard
will expand to include additional facilities that impact reliability
that currently are not covered by this Reliability Standard. A
modification that reduces the applicability of this Reliability
Standard would not meet the Commission's directives. In response to
SoCal Edison's argument that the Reliability Standard already addresses
the Commission's concerns, the Commission agrees that while there
appears to be a mechanism for inclusion of additional lines, none have
been included. This lack of inclusion is in spite of the evidence that
some lower voltage lines can have significant impacts on the Bulk-Power
System, including IROLs and SOLs.
712. In response to APPA, NRECA and NERC we agree that the proposed
modifications should be vetted through the Reliability Standards
development process. The Commission's goal is to promote the Reliable
Operation of the Bulk-Power System by including all of those entities
necessary to comply with this Reliability Standard. We believe that
requiring the Reliability Standard to include a greater number of
entities and exclude those that will not affect reliability will more
effectively sustain reliability than an overly exclusive list of
applicable entities.
ii. Inspection Cycles
713. In the NOPR, the Commission proposed to direct NERC to submit
a modification to FAC-003-1 that requires the ERO to develop a minimum
vegetation inspection cycle that allows variation for physical
differences.
(a) Comments
714. FirstEnergy states that a designation of a minimum annual
inspection cycle is appropriate and the method of inspection (aerial or
by ground) should be left to the transmission owner. Dominion cautions
that if there is a requirement for annual inspections, it should be
flexible and allow for different approaches to transmission line
inspections.
715. APPA, Entergy, EEI, LPPC, Progress Energy, SERC and SoCal
Edison disagree with the Commission's proposal to require the ERO to
set minimum vegetation inspection cycles that allow for physical
differences. APPA, Entergy and LPPC say that, instead of proposing the
development of a Reliability Standard for minimum vegetation inspection
cycles, the Commission should permit the transmission system owner or
local utility to determine the inspection cycle best suited for its
system and adhere to that cycle, with compliance enforcement performed
by the Regional Entities and the ERO.
716. Progress Energy and SERC believe that the Reliability Standard
as written provides flexibility regarding vegetation inspection cycles
and that the Commission should not impose requirements on the ERO to
develop minimum inspection intervals on a continent with such regional
diversity in climate and vegetation. In addition, Progress Energy
argues that, where a particular region is heavily forested and has
heavy rainfall along with extended or year round growing seasons, a
``back stop'' minimum inspection frequency could lead transmission
owners to conduct inspections less frequently than what the local
conditions require, which would lead to a lowest common denominator
Reliability Standard. This
[[Page 16489]]
could result in a transmission owner complying with the Reliability
Standard while not adequately protecting the reliability of that
region's transmission system.
717. Progress Energy and SERC argue that, since the performance
metrics in FAC-003-1 require reporting of applicable transmission
interruptions caused by vegetation, the compliance process associated
with this Reliability Standard should appropriately identify
transmission owners' inspection cycles that are not adequate, and the
ERO can use its authority to remedy any vegetation-related outage that
is attributed to the transmission owner's inspection frequency.
718. SoCal Edison states that transmission owners are already
obligated by Requirement R1.1 to establish a minimum vegetation
inspection schedule that allows adjustment for changing conditions.
SoCal Edison believes that the best measure of an effective
transmission vegetation management program is whether or not tree-to-
line contacts are occurring. SoCal Edison recommends the Commission
rescind the two proposed directives and order no further revisions to
FAC-003-1 until such time as Reliability Standard is deemed
unenforceable by the ERO or is not otherwise achieving its stated
goals.
719. APPA and Progress Energy state that a minimum vegetation
inspection cycle could result in an undue financial burden for some
regions of the country, because they would be forced into a minimum
cycle that might be inappropriate for their own region. For example,
Progress Energy states that, where a particular region is arid,
sparsely forested or has a minimum growing season, a ``back stop''
minimum could require a more frequent interval than is realistically
needed. This would result in increased and unnecessary costs to the
transmission owner and its customers without providing a comparable
increase in reliability. EEI believes that a minimum inspection cycle
will add nothing to the strength of the existing practices and could
add a requirement that is not merited by actual circumstances in many
locations.
(b) Commission Determination
720. The Commission is concerned about minimizing outages and
supports a realistic inspection cycle. In the NOPR, the Commission
proposed a minimum inspection cycle that takes account of physical
differences as one way to address this concern. However, we recognize
that there may be other options to achieve the same reliability goal.
For example, the ERO could determine whether a prepared company-
tailored inspection cycle is appropriate given the physical and
geographic factors and, through audits, inspect individual vegetation
management programs for compliance.
721. While the Commission disagrees that incorporating a backstop
would lead to a lowest common denominator Reliability Standard, the
Commission is dissuaded from requiring the ERO to create a backstop
inspection cycle at this time. Instead, the Commission agrees that an
entity's vegetation management program should be tailored to
anticipated growth in the region and take into account other
environmental factors. The goal is to assure that transmission owners
conduct inspections at reasonable intervals. In the Commission's
Vegetation Management Report, we found that many entities performed
aerial or ground inspections less than every three years or even ``as
needed.'' \264\
---------------------------------------------------------------------------
\264\ Utility Vegetation Management and Bulk Electric
Reliability Report at 10-11, available at http://www.ferc.gov/industries/electric/indus-act/reliability/2004.asp
(Vegetation
Management Report).
---------------------------------------------------------------------------
722. The Commission continues to be concerned with leaving complete
discretion to the transmission owners in determining inspection cycles,
which limits the effectiveness of the Reliability Standard.
Accordingly, the Commission directs the ERO to develop compliance audit
procedures, using relevant industry experts, which would identify
appropriate inspection cycles based on local factors. These inspection
cycles are to be used in compliance auditing of FAC-003-1 by the ERO or
Regional Entity to ensure such inspection cycles and vegetation
management requirements are properly met by the responsible entities.
iii. Minimum Clearances on National Forest Service Lands
723. In the NOPR, the Commission did not propose to modify the
ERO's general approach with respect to clearances. However, the
Commission expressed its belief that any potential issues regarding
minimum clearances on National Forest Service (Forest Service) lands
should be dealt with on a case-by-case basis. The Commission requested
comments on whether another approach would be more appropriate to
address this issue.
(a) Comments
724. APPA believes that a case-by-case approach may have to be
employed, since Forest Service lands are located all across the country
and have different regional characteristics. APPA notes that U.S. Fish
and Wildlife Service personnel have begun to take action regarding
vegetation management on non-federal lands, and reports that APPA
members have been told by U.S. Fish and Wildlife personnel to refrain
from cutting vegetation at certain times of the year in the absence of
an imminent reliability threat. APPA concludes that this information
conflicts with specifying minimum nationwide vegetation inspection/
cutting cycles and clearances. In addition, APPA requests clarification
of the Commission interpretation ``we interpret the FAC-003-1 to
require trimming that is sufficient to prevent outages due to
vegetation management practices under all applicable conditions.''
725. Several commenters express concern about the Commission's
position that any potential issues regarding minimum clearances on
National Forest Service lands should be dealt with on a case-by-case
basis.\265\ EEI, Progress Energy and SERC believe that this approach is
inconsistent with the Reliability Standard's intent to use consistent
approaches in setting minimum vegetation clearance distances on both
private and public lands and the Commission's statement that this
Reliability Standard requires minimum clearances that are ``sufficient
to prevent outages due to vegetation management practices under all
applicable conditions.'' \266\ Therefore, International Transmission,
EEI, LPPC, Progress Energy and SERC assert that Reliability Standard
FAC-003-1 should be applicable to all responsible entities including
those with transmission on both private and public lands because
consistency is the only way to provide a uniform and reliable
electrical system. Dominion suggests the Commission defer to NERC and
the stakeholder process to develop specifications for clearances.
---------------------------------------------------------------------------
\265\ See, e.g., EEI, Energy, International Transmission,
Progress Energy, SERC, LPPC and MISO.
\266\ The NOPR states that ``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*
* *'' NOPR at P 380.
---------------------------------------------------------------------------
726. Progress Energy and SERC note that EEI and certain federal
agencies \267\ have jointly addressed the issue of consistency in
vegetation management work on federal lands, and developed a memorandum
of understanding (Vegetation MOU) which sets the framework for managing
vegetation on transmission line rights-of-way under
[[Page 16490]]
Federal agency jurisdiction.\268\ Progress Energy and SERC recommend
using the EEI's Vegetation MOU framework for managing vegetation on
transmission line rights-of-way under federal agency jurisdiction
rather than the case-by-case approach proposed in the NOPR. LPPC
recommends creating a bright-line when it comes to utilities'
obligations (and rights) for trimming vegetation located on Forest
Service lands. Avista and Portland General ask that the Vegetation MOU
be affirmed by the Commission and permitted to govern transmission line
rights-of-ways located on lands managed by federal land management
agencies.
---------------------------------------------------------------------------
\267\ Forest Service, Bureau of Land Management, Fish & Wildlife
Service, National Park Service, and U.S. Environmental Protection
Agency.
\268\ The Vegetation MOU is available at http://www.eei.org/industry_issues/environment/land/vegetation_management/EEI_MOU_FINAL_5-25-06.pdf
.
---------------------------------------------------------------------------
727. SoCal Edison believes that transmission owners should be
allowed the latitude to establish measures/procedures for less rigid
tree-to-line clearances in response to state and federal agency demands
or requests but is concerned that these measures/procedures will prove
to be of little or no value in the event of an ERO investigation into a
tree-to-line contact occurring within national/state forestry
boundaries or on private property.
728. California PUC points out that California already has
requirements applicable to minimum vegetation clearance, and that the
Commission must take care to assure that any mandatory Reliability
Standard does not preempt the ability of California (and other states
with similar state standards) to impose stricter requirements that have
no adverse impacts on reliability.
729. FirstEnergy states that the standard should define rights-of-
way to encompass the required clearance area instead of the
corresponding legal land rights. Some rights-of-way may be larger to
accommodate future needs and therefore may exceed clearances needed for
existing lines. FirstEnergy believes that Reliability Standards should
not require clearing entire rights-of-way when the required clearance
for existing lines does not take up the entire right-of-way.
(b) Commission Determination
730. As proposed in the NOPR, the Commission approves Reliability
Standard FAC-003-1 with no proposed modification on the issue of
clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation
management practices under all applicable conditions. As to APPA's
requests for clarification concerning the term ``under all applicable
conditions,'' the Reliability Standard already addresses this issue in
Requirement R3.2 by allowing for exceptions for natural disasters
(including wind shears and major storms) that cause vegetation to fall
into the transmission lines from outside the ROW. The Commission
therefore finds that no clarification is required in response to APPA.
731. The Commission agrees that ownership of the land does not
change the impact of a vegetation-related outage on the Bulk-Power
System. However, the present Reliability Standard leaves the
determination and documentation of ``clearance 1'' to transmission
owners. As such, there are no specific clearances, or criteria/
procedures to develop clearances, before the Commission for approval.
What is in front of the Commission relative to ``locations on the
right-of-way where the Transmission Owner is restricted from attaining
the clearances specified in Requirement R1.2.1'' is addressed in
Requirement R1.4. Requirement R1.4 states that ``Each Transmission
Owner shall develop mitigation measures to achieve sufficient
clearances for the protection of the transmission facilities when it
identifies locations on the right-of-way where the Transmission Owner
is restricted from attaining the clearances specified in Requirement
R1.2.1.'' This Requirement addresses the instances when an entity
cannot attain the clearances that it needs on land that it controls.
Since there are multiple mitigation measures that the entity can employ
to achieve the goal of preventing outages due to vegetation management
practices, the Commission has stated that any potential issues
regarding minimum clearances on Forest Service lands should be dealt
with on a case-by-case basis.
732. Avista and Portland General ask the Commission to endorse the
Vegetation MOU. The Commission reiterates its direction that the
minimum clearances must be sufficient to avoid any sustained
vegetation-related outages for all applicable conditions. The
Vegetation MOU references IEEE 516 as the only way to determine
applicable minimum clearances. The Commission declines to endorse the
use of IEEE 516 as the only minimum clearance because it is intended
for use as a guide by highly-trained maintenance personnel to carry out
live-line work using specialized tools under controlled environments
and operating conditions, not for those conditions necessary to safely
carry out vegetation management practices.\269\ Further, the allowable
clearances in the IEEE standard are significantly lower than those
specified by the relevant U.S. safety codes. As such, use of IEEE
clearance provision as a basis for minimum clearance prior to the next
tree trimming as a Requirement in vegetation management is not
appropriate for safety and reliability reasons. For example, the IEEE
Standard 516-2003 specifies a 2.45-foot clearance from a live conductor
for the 120 kV voltage class,\270\ whereas the ANSI Z-133 standard
specifies 12 feet, 4 inches as the approach distance for the 115 kV
voltage class.\271\
---------------------------------------------------------------------------
\269\ Controlled environments and operating conditions include
clear days without precipitation, high winds or lightning.
\270\ Institute of Electrical and Electronics Engineers, Inc.
(IEEE) Standard 516-2003, IEEE Guide for Maintenance Methods at 20.
\271\ ANSI Z133, American National Standards Institute Standard
for Tree Care Operations--Pruning, Trimming, Repairing, Maintaining
and Removing Trees, and Cutting Brush--Safety Requirements.
---------------------------------------------------------------------------
733. Accordingly, the Commission directs the ERO to develop a
Reliability Standard that defines the minimum clearance needed to avoid
sustained vegetation-related outages that would apply to transmission
lines crossing both federal land and non-federal land. While this
consensus is developed, the Commission directs the ERO to address any
potential issues regarding mitigation measures needed to assure these
minimum clearances on Forest Service lands are appropriate on a case-
by-case basis. The Commission also directs the ERO to collect outage
data for transmission outages of lines that cross both federal and non-
federal lands, analyze it, and use the results of this analysis and
information to develop a Reliability Standard that would apply to
transmission lines crossing both federal and non-federal land.
734. In regard to California PUC's concern about its ability to
impose stricter requirements on vegetation clearances, the Commission
notes that section 215(i)(3) of the FPA states that nothing in section
215 shall be construed to preempt the authority of a state to take
action to ensure the reliability of electric service within that state,
as long as the action is not inconsistent with any Reliability
Standard. Therefore, the State of California may set its own vegetation
management requirements that are stricter than those set by the
Commission as long as they do not conflict with those set by the
Commission. Further, the Commission notes that once a Reliability
Standard is established, California PUC can develop stricter rules to
be applied within the
[[Page 16491]]
state of California, and if it wants them to be enforceable under
section 215 of the FPA, could submit those Reliability Standards to the
ERO and the Commission for approval as a regional difference.
735. FirstEnergy suggests that rights-of-way be defined to
encompass the required clearance areas instead of the corresponding
legal rights, and that the standards should not require clearing the
entire right-of-way when the required clearance for an existing line
does not take up the entire right-of-way. The Commission believes this
suggestion is reasonable and should be addressed by the ERO.
Accordingly, the Commission directs the ERO to address this suggestion
in the Reliability Standards development process.
iv. Summary of Commission Determinations
736. The Commission approves FAC-003-1 as mandatory as enforceable.
In addition, while we do not direct the ERO to submit a modification to
the general limitation on applicability as proposed in the NOPR, we
require the ERO to address the proposed modification through its
Reliability Standards development process as discussed above. Further,
while the Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time, it directs the ERO to develop
compliance audit procedures to identify appropriate inspection cycles
based on local factors. These inspection cycles are to be used in
compliance auditing of FAC-003-1 by the ERO or Regional Entity to
ensure such inspection cycles and vegetation management requirements
are properly met by the responsible entities. Finally, the Commission
directs the ERO to develop a Reliability Standard through the
Reliability Standard development process that defines the minimum
clearance needed to avoid sustained vegetation-related outages that
would apply to transmission lines crossing both federal land and non-
federal land. While this consensus is developed, the Commission directs
the ERO to address any potential issues regarding mitigation measures
needed to assure these minimum clearances on Forest Service lands are
appropriate on a case-by-case basis. The Commission also directs the
ERO to collect outage data for transmission outages of lines that cross
both federal and non-federal lands, analyze it, and use the results of
this analysis and information to develop a Reliability Standard that
would apply to transmission lines crossing both federal and non-federal
land.
d. Facility Ratings Methodology (FAC-008-1)
737. FAC-008-1 requires each transmission owner and generation
owner to develop a facility rating methodology for its facilities,
which should consider manufacturing data, design criteria (such as
IEEE, ANSI or other industry methods), 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.
738. In the NOPR, the Commission proposed 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 proposed to direct NERC to develop a modification to
FAC-008-1 through the Reliability Standards development process that
requires transmission and generation facility owners to: (1) Document
underlying assumptions and methods used to determine normal and
emergency facility ratings; (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 the
increase in rating based on the next limiting component(s) for all
critical facilities.
i. Methodology Used To Determine Facility Ratings and Documentation of
Underlying Assumptions
(a) Comments
739. EEI, Valley Group, MidAmerican and TANC support the
Commission's proposal to require additional documentation as a
reasonable means to provide more transparency and consistency. EEI
suggests that this requirement could be accommodated with a provision
for the disclosure of such information upon request by a registered
user, owner or operator. TANC supports the Commission's proposal to not
require a uniform facility rating methodology and recommends that the
Commission adopt a policy that provides for each transmission owner and
generation owner to develop and document a facility rating methodology,
which is consistent with industry methodologies, for their facilities.
TANC also states that the methodology used for developing facility
ratings should include a description of and justification for all of
the assumptions. Valley Group states that it is extremely important
that the underlying assumptions and methods are documented and known to
all parties. Valley Group maintains that this will also ensure that the
rating assumptions used by operating and planning functions are
consistent with each other. Valley Group emphasizes that making these
assumptions open is important, especially regarding paths between
different transmission owners, to ensure that transmission owners
cannot exercise market power. It argues that open assumptions will also
provide rational grounds for dispute resolution.
(b) Commission Determination
740. As EEI, TANC, Valley Group and MidAmerican discuss in their
comments, the Commission's proposal to modify FAC-008-1 to require
additional documentation supports the Commission's goals of improving
uniformity and transparency in the facility ratings process. EEI's
suggestion that having this information available for review upon
request of a registered user, owner or operator should be considered by
the ERO in its Reliability Standards development process. As proposed
in the NOPR, the Commission directs the ERO to submit a modification to
FAC-008-1 that requires transmission and generation facility owners to
document underlying assumptions and methods used to determine normal
and emergency facility ratings. As stated in the NOPR, the Commission
believes that this added transparency will allow customers, regulators
and other affected users, owners and operators of the Bulk-Power System
to understand how facility owners set facility ratings through
differing methods that provide equivalent results.
ii. Rating Facilities Consistent with Industry Standards Developed
Through an Open Process such as IEEE and CIGRE
(a) Comments
741. The Valley Group states that the Commission correctly
identifies IEEE and CIGRE as examples of open process methodologies
suitable for overhead transmission line ratings calculations. It claims
that IEEE and CIGRE are the only methodologies which make their
algorithms available to everybody, and clearly document their
assumptions. Valley Group notes that both of these methodologies will
undergo a revision for accuracy regarding calculations for high
temperatures and high current densities in the next two years, which
may lead in some cases to slightly lower
[[Page 16492]]
line ratings, although the changes are not expected to be substantial.
742. APPA suggests that the proposal to rate facilities consistent
with industry methodologies developed through an open process such as
IEEE and CIGRE should be considered in the ERO's Reliability Standards
development process rather than ordered by the Commission. LPPC asks
the Commission to require only that facility ratings be consistent with
good utility practice. According to LPPC, to the extent facility rating
methodologies need to be more prescriptive than good utility practice,
the details must be spelled out in the ERO Reliability Standards
themselves, not by reference to other unspecified industry
methodologies. LPPC believes that it would be poor policy for the
Commission to endorse these methodologies since it would be impossible
to police the processes by which such organizations develop their
methodologies. MidAmerican states that the Commission should recognize
that the proposal to require facility ratings be consistent with
industry methodologies developed through an open process is potentially
problematic, noting that certain aspects of the development of facility
ratings are based on industry standards that are not developed through
an open process, such as information provided by engineering textbooks
or manufacturer information that is not specifically referenced in any
current standard. MidAmerican recommends that the Commission delete the
requirement that facility ratings be ``developed through an open
process such as IEEE or CIGRE'' or add other sources that the
Commission would find appropriate, such as the results of accepted
scientific and engineering investigations and common sense. MRO
requests that the Commission clarify whether its directive to modify
FAC-008-1 to develop facility ratings consistent with industry
standards developed through an open process such as IEEE or CIGRE would
allow for legitimate regional differences such as climate, terrain or
population density.
(b) Commission Determination
743. In the NOPR, the Commission stated, ``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.'' \272\ These
processes have been validated through actual testing and have been
shown to provide appropriate results. Information from engineering
textbooks, common sense or manufacturer information would be part of
the underlying assumptions. The Commission's intent in the NOPR was to
require that FAC-008-1 be modified to require that facility ratings be
developed consistent with industry standards developed through an open,
transparent and validated process. The Commission agrees with Valley
Group that IEEE and CIGRE are two examples of such processes and
disagrees with LPPC that reference to industry standards is poor
policy. Industry standards that have been verified by actual testing
are appropriate. However, the Commission agrees with MidAmerican that
IEEE and CIGRE are just two examples of such bodies; any other open
process that has been technically validated for its provision of
accurate, consistent ratings is also acceptable. The ERO should
consider the concerns raised by LPPC and MRO in its Reliability
Standards development process, and is hereby directed to do so. The
Commission does not expect there to be any regional differences because
the only differences should be from different underlying assumptions
that are not defined by the Reliability Standard.
---------------------------------------------------------------------------
\272\ NOPR at P 404.
---------------------------------------------------------------------------
iii. Identify the Limiting Component(s) and Define for All Critical
Facilities the Rating Based on the Next Limiting Component Within the
Same Facility
(a) Comments
744. TANC maintains that the rating information provided by the
transmission owners and generator owners should include additional
information about all of the limiting components of the elements (e.g.,
transmission lines, transformers, etc.) for all critical facilities.
Access to such information will enable neighboring systems to
accurately study the effects of other facilities on their own systems
and determine the critical elements for increasing facility ratings.
745. Valley Group states that identifying the limiting elements is
an excellent objective for reliability enhancement, but notes that its
granularity must be limited to major elements of the circuits, such as
transformers and breakers, while treating the transmission lines as
single elements. Valley Group also notes that, of the two examples
discussed in the NOPR, the example regarding relay settings is
technically well justified, whereas rating the line based on a single
limiting span is generally impractical because line design engineers
add to the National Electric Safety Code minimum requirements ``safety
buffers,'' which vary depending on their confidence in the accuracy of
design calculations.
746. APPA is concerned about the possible ``unintended
consequences'' of this modification and questions whether this proposed
Requirement can be done as a practical matter; how many critical
facilities and limiting components would have to be modeled to meet
such a Requirement; and whether the cost of such modeling is justified
by the reliability benefits. Dynegy, MISO and Wisconsin Electric also
oppose this requirement because it is ambiguous, the additional work
required to identify the increase in rating based on the next limiting
component(s) is unwarranted and potentially costly, and the need for
any such specific information is questionable. Dynegy and Wisconsin
Electric do not believe there is a widespread need for this type of
information and recommend that the need for it be explored on a case-
by-case basis rather than including a global requirement in the
standards.
747. Dynegy, FirstEnergy and MISO state that it is not clear what
specific criteria would be used to define ``critical facilities'' and
``limits.'' EEI also states that developing a practical definition of
``critical facilities'' presents a challenge, and that compliance would
require the analysis of possibly hundreds of thousands of ``limiting''
transmission elements to determine whether a limit is of primary
concern or is contingent on the status of other nearby elements or
system conditions at a particular time. EEI suggests that, rather than
requesting that the industry develop a definition, it may be more
useful for the Commission to recommend that the industry develop a set
of high-level criteria that could be used to identify those
transmission elements that create significant potential limits that are
independent of other factors and considerations.
748. EEI and TVA assert this recommendation does not seem to be
intended to enhance reliability but to provide additional commercial
information to the market, and may not be appropriate to include in a
Reliability Standard. Portland General further points out that this
information can be obtained from a transmission provider by submitting
a transmission or interconnection request when ATC is not posted or not
available. TVA comments that, since the focus of this proceeding is the
Reliable Operation of the Bulk-Power System, changes to a proposed
Reliability Standard, such as FAC-008-1, that appear designed to
promote maximum commercial use of the grid are unwarranted in this
[[Page 16493]]
proceeding and could jeopardize, rather than further, reliable
transmission system operations.
749. MRO seeks clarification about whether the proposed
modification will require that all limiting facilities elements be
published. MRO believes that serious confidentiality issues are raised
due to the security-sensitive nature of the information and urges the
Commission not to require the publication of such information.
750. Dominion states that the Commission should exclude from this
requirement facilities that are covered under an open, regional
transmission expansion planning process, such as the Regional
Transmission Expansion Plan process in PJM, where any interested party
can be involved in the studies and determine what the limitations are
and what could be done to increase transmission capacity.
751. International Transmission states that, if the Commission were
to require defining the increase in facility rating based on the next
limiting element, it should restrict such application to transmission
elements where the conductor itself is not the limiting element.
International Transmission explains that in cases where the line must
be completely rebuilt, it would not be feasible to estimate the
increase in facility rating, since the new line could be specified to
carry virtually any amount of power.
752. MISO questions how a generator operator or generation owner
would identify the increase in rating based on the next most limiting
component(s) associated with generator output. FirstEnergy believes
that this modification should recognize that generators may need to
rely on transmission owners to point out facilities that are more
limiting than the generator facilities.
753. Manitoba's technical experts disagree with the Preliminary
Staff Assessment regarding FAC-008-1. The Reliability Standard properly
places the responsibility of determining facility ratings with the
facility owners. Manitoba also states that, since this Reliability
Standard requires that the ``Facility Rating shall be equal to the most
limiting applicable Equipment Rating of the individual equipment that
comprises that Facility,'' information on the next limiting component
is already identified. Contrary to the Commission's view, Manitoba does
not believe it would be appropriate in this Reliability Standard to
identify the increase in rating for all critical facilities based on
the next limiting component. In a networked system, there may be other
limitations that set the current carrying capability of the critical
facility.
754. Manitoba further notes that the Commission proposal may lead
to international conflicts in Reliability Standards. Manitoba states
that a mandated change to FAC-008-1, which forces an entity to accept
facility ratings beyond its risk tolerance, would be grounds for
Manitoba to recommend that the provincial government of Manitoba not
approve this Reliability Standard because it would degrade reliability.
755. APPA suggests that the proposal to identify the limiting
component and define for all critical facilities the rating based on
the next limiting component be considered in the ERO's Reliability
Standards development process rather than ordered by the Commission.
(b) Commission Determination
756. The Commission agrees with TANC that this modification would
provide useful information to neighboring systems and users, owners and
operators of the Bulk-Power System. The Commission also agrees with
Valley Group that identifying the limiting elements of facilities
enhances reliability by providing operators specific information about
the limiting elements and therefore allowing them to assess the risks
associated with circuit loadings.
757. In response to the comments of APPA, Dynegy, EEI, MISO and
Wisconsin Electric, the Commission clarifies that this Reliability
Standard and the Commission's proposed modification apply to
facilities. As defined in the NERC glossary, a facility is ``a set of
electrical equipment that operates as a single Bulk Electric System
Element \273\ (e.g., a line, a generator, a shunt compensator,
transformer, etc.).'' The most limiting component in a facility
determines its rating, just like the rating of a chain is determined by
the weakest link. The Commission's proposed modification would require
identifying and documenting the limiting component for all facilities
and the increase in rating if that component were no longer the most
limiting component; in other words, the rating based on the second-most
limiting component. The Commission further clarifies that this
Reliability Standard will require this additional thermal rating
information only for those facilities for which thermal ratings cause
the following: (1) An IROL; (2) a limitation of TTC; (3) an impediment
to generation deliverability or (4) an impediment to service to major
cities or load pockets.
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\273\ An element is made up of one or more components.
---------------------------------------------------------------------------
758. EEI and TVA raise concerns that this modification promotes
commercial use of the grid rather than ensuring Reliable Operation of
the Bulk-Power System, and relates more to transmission access than
reliable operations. The Commission disagrees that this modification
relates primarily to transmission access. When the transmission
operators know which component within the transmission element is
limiting they have more information to inform their decisions about how
to provide for the Reliable Operation of the Bulk-Power System. Our
proposed modification does not require any entity to invest in
equipment to increase ratings of any facility; it simply requires the
next limiting component of each facility to be identified in order to
understand what components are causing the limits that are to be used
in reliability mitigation assessments. The identification of the first
limiting component is already an inherent requirement in the existing
rating process. As clarified above, the modification to identify an
increase in rating of the transmission element that would result from
removing the first limitating component applies only to critical
facilities whose thermal ratings have been reached causing an SOL or
IROL condition. As Dominion highlights in its comments, this
information is already identified in the planning processes of some
RTOs and ISOs.
759. In response to the concerns raised by EEI and MRO about
sharing confidential, market-sensitive information, the Commission
disagrees that ratings information is confidential or market-sensitive.
All users, owners and operators should have access to the facility
ratings in order to operate the system reliably. Section 215(a)(4) of
the FPA defines Reliable Operation, in part, as operating the elements
of the Bulk-Power System within equipment and electric system thermal
stability limits.\274\ Without knowing the ratings, it is not possible
to know whether this requirement is being met. As to the argument that
this information is confidential, the Commission clarifies that, as
with the other information required by this Reliability Standard, the
additional information required by this modification would be shared
only with users, owners and operators of the Bulk-Power System.
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\274\ 16 U.S.C. 824o(a)(4).
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760. In response to Dominion's comments, if the PJM Regional
Transmission Expansion Planning process meets the criteria, there is no
[[Page 16494]]
need to exclude facilities covered by that process from this
requirement.
761. The Commission directs the ERO to consider International
Transmission's comments regarding requiring information about the
increase in facility rating based on the next limiting element only for
lines where the conductor itself is not the limiting element in its
Reliability Standards development process. Similarly, the ERO should
also consider the comments from MISO and FirstEnergy that generators
will have difficulty determining the increase in ratings due to the
next limiting element, since in most cases the generator itself would
be the most limiting element.
762. We agree with Manitoba that this Reliability Standard properly
places the responsibility to determine facility ratings on the facility
owner. The Commission is not proposing to change this. We also agree
with Manitoba that the most limiting component is already identified
when facility ratings are determined. The Commission is only directing
transmission and generation owners to provide additional information on
the next limiting component within the facility so that facility
ratings are more transparent.
763. In response to Manitoba's and APPA's concerns, we recognize
that this is an additional requirement with some complexities, and this
modification will go through the ERO Reliability Standards development
process. We do not intend to usurp the Reliability Standards
development process, where Manitoba may raise its concerns for the ERO
to consider.
iv. Applicability to Generator Owners
(a) Comments
764. Xcel states that this Reliability Standard should not apply to
generator owners because capability testing, rather than using
mathematical calculations, is the preferred method of determining
generating unit capability. Capability testing clearly includes the
capability of all the supporting components behind the generator that
are required to produce a MW of capability. Xcel also states that this
proposed Reliability Standard, if applied to generating units, would
not improve system reliability and could result in conflicting and
confusing unit capability ratings. Xcel notes that generating units
already are required to be capability-tested on a periodic and seasonal
basis to demonstrate unit gross and net capability in accordance with
proposed standards MOD-024-1 and MOD-025-1.
765. FirstEnergy also points out that facility ratings for nuclear
units are part of NRC license agreements and that the ratings
methodologies included in NRC license agreements are approved by NRC.
FirstEnergy proposes that compliance with NRC ratings methodology
requirements should be assumed to comply with this Reliability
Standard.
(b) Commission Determination
766. The Commission agrees with Xcel that an actual test could be
used as a substitute for a mathematical calculation of capability, and
we ask the ERO to consider these comments in its Reliability Standards
development process. The Commission understands that NRC provides
ratings methodologies for nuclear power plants and not for the
transmission system. Capacity ratings of nuclear generators determined
using this methodology are acceptable for reliability purposes. We also
direct the ERO to consider FirstEnergy's comments in its Reliability
Standards development process.
v. Compliance With Blackout Report Recommendation No. 27
(a) Comments
767. Manitoba believes this Reliability Standard meets the
requirement of Blackout Report Recommendation No. 27 because the
recommendation does not require a uniform set of methodologies for
rating facilities, but instead only recommends that there be a clear,
unambiguous requirement to rate transmission lines.
768. Valley Group notes that, while the Commission's proposal would
direct the ERO to respond to a part of Blackout Report Recommendation
No. 27, it does not address the important second part of the
Recommendation, namely dynamic ratings. Valley Group notes that dynamic
ratings offer a very powerful tool both for maximizing the capabilities
of transmission paths and for avoiding unnecessary transmission line
loading relief. Valley Group also notes that dynamic ratings, based
either on ambient-adjusted ratings or ratings generated by real-time
monitoring systems, are widely used in the PJM system, while broader
real-time ratings are applied on certain lines in SPP and ERCOT and at
several individual utilities. Valley Group states that controlling
unnecessary operator interventions with dynamic ratings both increases
the reliability of Bulk-Power System and improves its economy. Valley
Group concludes that it would be highly desirable for the ERO to
establish policies and procedures regarding dynamic ratings--as
recommended by the Blackout Report, and recommends that the Commission
include such guidance in its Final Rule.
(b) Commission Determination
769. The Commission believes that implementation of the
modifications discussed earlier to Reliability Standard FAC-008-1 meets
our goal of implementing Blackout Report Recommendation No. 27, which
is to ``develop enforceable standards for transmission line ratings.''
\275\ To achieve a clear and unambiguous Requirement to rate
transmission lines, it is important to understand the underlying
assumptions and the methodologies that will be used to develop those
ratings. The Commission recognizes that dynamic line ratings are an
innovative application, and directs the ERO to consider the comments
from Valley Group in future revisions of this Reliability Standard.
---------------------------------------------------------------------------
\275\ Blackout Report at 162.
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vi. General Comments
770. APPA notes that FAC-008-1 should be revised to replace Levels
of Non-Compliance with Violation Security Levels, and to include
Violation Risk Factors on all FAC-008-1 requirements.
(a) Commission Determination
771. The Commission acknowledges that the Reliability Standards are
changing. In this Final Rule, we are ruling on the Reliability
Standards as they were filed, and these documents use the term Levels
of Non-Compliance. The ERO should address APPA's comments in its
Reliability Standards development process.
vii. Summary of Commission Determination
772. Accordingly, as discussed in the responses to comments above,
the Commission approves FAC-008-1 as mandatory and enforceable. In
addition, we direct the ERO to develop modifications to FAC-008-1
through its Reliability Standards development process requiring
transmission and generation facility owners to: (1) Document underlying
assumptions and methods used to determine normal and emergency facility
ratings; (2) develop facility ratings consistent with industry
standards developed through an open, transparent and validated process
and (3) for each facility, identify the limiting component and, for
critical facilities, the resulting increase in rating if that component
is no longer limiting.
[[Page 16495]]
e. Establish and Communicate Facility Ratings (FAC-009-1)
773. FAC-009-1 requires each transmission owner and generation
owner to establish facility ratings consistent with its associated
facility ratings methodology and provide those ratings to its
reliability coordinator, transmission operator, transmission planner
and planning authority. In the NOPR, the Commission proposed to approve
FAC-009-1 as mandatory and enforceable.
i. Comments
774. APPA supports approval of FAC-009-1 as a mandatory and
enforceable Reliability Standard.
ii. Commission Determination
775. 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 approves Reliability Standard
FAC-009-1 as mandatory and enforceable.
f. Transfer Capability Methodology (FAC-012-1)
776. Proposed Reliability Standard FAC-012-1 requires each
reliability coordinator and planning authority to document the
methodology used to develop its 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.
777. In the NOPR, the Commission explained that, because 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. Thus, the NOPR did not
propose to approve or remand this Reliability Standard until the
regional procedures are submitted.
778. The NOPR explained that FAC-012-1 only requires that the
regional reliability organization provide documentation on transfer
capability methodology and provide it to entities such as the relevant
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. The NOPR suggested
that FAC-012-1 should, as a minimum, provide a framework for the
transfer capability calculation methodology including data inputs and
modeling assumptions. In addition, the NOPR asked for comments on the
most efficient way to make the above information transparent for all
participants.
i. Methodology
(a) Comments
779. APPA, International Transmission and MidAmerican agree that
the proposed FAC-012-1 is not sufficient and should not be accepted for
approval as a mandatory Reliability Standard. They suggest that, at a
minimum, this Reliability Standard should provide a framework for the
transfer capability calculation methodology, including data inputs and
modeling assumptions. APPA notes that, in the Western Interconnection
and ERCOT, the sets of rules for long-range and operational planning
studies are transparent to all users, owners and operators and suggests
that in the Eastern Interconnection, where multiple regions exist, the
Regional Entities should consider developing an umbrella organization
or process comprised of representatives from each of the Eastern
Interconnection's Regional Entities to establish the planning and
operational rules for the Interconnection. APPA suggests that this
approach would work well to identify critical facilities, by using
consistent and transparent study assumptions, and it would also
minimize seams issues when establishing facility rating and transfer
capabilities throughout the entire Interconnection. International
Transmission states that this Reliability Standard should identify the
performance that is required, that specifics of how transfer capability
should be calculated do not belong in this Reliability Standard, and
that a reference document could be developed for this purpose.
(b) Commission Determination
780. Although we are not proposing to approve or remand this
Reliability Standard, because it is applicable to the regional
reliability organization, the Commission agrees with APPA,
International Transmission and MidAmerican that, at a minimum, this
Reliability Standard should provide a framework for the transfer
capability calculation methodology, including data inputs and modeling
assumptions. The Commission agrees with APPA that there should be an
umbrella organization to assure consistency within the Eastern
Interconnection and the other interconnections. We believe that the
best organization to do this would be the ERO, because it is the only
organization with knowledge of all of the individual Regional Entities
that can carry out this function. Therefore, we direct the ERO to
modify this Reliability Standard to provide such a framework.
ii. Transparency and Confidentiality
(a) Comments
781. International Transmission cautions that, in making
information regarding the framework for calculating transfer capability
transparent to all participants, a balance must be maintained between
the need for transparency and the need to maintain the confidentiality
of sensitive critical energy infrastructure information (CEII). The
results of certain critical contingency analyses would not be
appropriate for public disclosure, but may be the basis for transfer
capability limits imposed on some interfaces.
782. MidAmerican suggests that transparency could be provided in
the Eastern Interconnection by each reliability coordinator and each
planning authority posting the transfer capability calculations
performed pursuant to FAC-012-1, along with a document outlining how
they were determined and the purposes for which they are used on a
protected Web site. The protected site should be accessible only to
qualified entities. MidAmerican suggests that the Western
Interconnection's approach, the WECC message system used for certain
qualified paths, is an appropriately transparent system.
(b) Commission Determination
783. Although we are not proposing to approve or remand this
proposed Reliability Standard, the Commission believes that it can be
improved. The Commission believes that the process used to determine
transfer capabilities should be transparent to the stakeholders, and
agrees with International Transmission and MidAmerican that the results
of those calculations should not be available for public disclosure but
only for qualified entities on a confidential basis. In addition, the
process and criteria used to determine transfer capabilities must be
consistent with the process and
[[Page 16496]]
criteria used for other users of the Bulk-Power System. Simply stated,
the criteria used to calculate transfer capabilities for use in
determining ATC must be identical to those used in planning and
operating the system. The Commission directs the ERO to take this into
account in its Reliability Standards development process, and to modify
the Reliability Standard consistent with Order No. 890 in Docket No.
RM05-25-000.
784. Accordingly, the Commission affirms the NOPR proposal to not
approve or remand this Reliability Standard. We understand that the ERO
implemented its Reliability Standards development process to revise the
Reliability Standard and will be submitting it in accordance with the
schedule identified in Order No. 890.
g. Establish and Communicate Transfer Capability (FAC-013-1)
785. FAC-013-1 requires either the reliability coordinator or the
planning authority, as determined by the regional reliability
organization, to calculate transfer capabilities consistent with its
transfer capability methodology and provide those capabilities to its
transmission operators, transmission service providers and planning
authorities.
786. In the NOPR, the Commission proposed 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 proposed to direct NERC to develop a modification to
FAC-013-1 that: (1) Makes it applicable to all reliability coordinators
and (2) removes the regional reliability organization as the entity
that determines whether a planning authority has a role in determining
transfer capabilities.
i. Comments
787. APPA supports the Commission's proposal to approve FAC-013-1
as a mandatory and enforceable Reliability Standard, but disagrees with
the Commission's proposed modification to remove the regional
reliability organization as the entity that determines whether a
planning authority has a role in determining transfer capabilities.
APPA believes that regional committee processes are essential to
determine, through their planning and operating committees, which
planning authorities and reliability coordinators are responsible for
determining and distributing each of the specific transfer capability
values within each regional footprint. APPA proposes that in the
Eastern Interconnection, where multiple regional reliability
organizations and Regional Entities exist, the Regional Entities should
consider developing an umbrella organization or process comprised of
representatives from each of the Eastern Interconnection's Regional
Entities, to establish the planning and operational planning rules for
the Interconnection. APPA believes that such a program would minimize
seams issues when establishing facility ratings and transfer
capabilities throughout the entire Interconnection.
788. MidAmerican supports the Commission's proposal to make this
Reliability Standard applicable to all reliability coordinators and
planning authorities. MidAmerican believes in a clear separation of
responsibilities between the reliability coordinators and planning
authorities. MidAmerican believes that reliability coordinators should
calculate transfer capabilities in the operating horizon, while
planning authorities calculate transfer capabilities in the planning
horizon, and would support additional clarification of the standard by
explicitly stating the continued responsibility of planning authorities
to calculate transfer capabilities for the planning horizon.
789. TANC is concerned that, if the transmission service provider
and the transmission operators are specifically named in Requirement
R2.1 of this Reliability Standard, but are not included in the
Applicability section, this will cause ambiguity. TANC questions
whether a transmission service provider or transmission operator that
does not receive the transfer capabilities from the reliability
coordinator will be held accountable and penalized for not producing
the transfer capabilities when the reliability coordinator never
provided them. If this is the case, TANC questions whether there will
be different penalties for the transmission service provider and
transmission operator, or whether they will be subject to the same
penalties as the entities listed in the Applicability section.
790. EEI believes that the full range of issues discussed here are
currently under review under Docket No. RM05-25 and proposes that these
issues remain in a single forum to avoid confusion.
ii. Commission Determination
791. The Commission does not believe that the regional reliability
organization should be able to decide the type of entity to which this
Reliability Standard applies. The Commission disagrees with APPA that
regional committee processes are essential to determine which planning
authorities and reliability coordinators are responsible for
determining and distributing each of the specific transfer capability
values. Reliability coordinators have a wider-area view of the
transmission system than planning authorities, which is important in
calculating inter- and intra-regional transfer capabilities. Therefore,
the Commission agrees with MidAmerican that reliability coordinators
should calculate transfer capabilities in the operating horizon. The
Commission will not address MidAmerican's proposal regarding
calculating transfer capabilities in the planning horizon because those
Reliability Standards are being considered in Docket No. RM07-3-000 and
are therefore beyond the scope of this proceeding.
792. The Commission, as discussed elsewhere in this Final Rule, has
considered APPA's proposal concerning creating an umbrella organization
in regard to FAC-012-001.\276\
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\276\ See supra P 780.
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793. In regard to TANC's concern that transmission service
providers and transmission operators may be liable because they are
specifically named in Requirement R2.1, the Commission clarifies that,
because the Reliability Standard only provides that the transmission
service providers and transmission operators receive information
regarding transfer capabilities, and does not require an affirmative
action on the part of transmission service providers or transmission
operators, a transmission service provider or transmission operator
cannot be liable for violating the Reliability Standard.
794. The Commission disagrees with EEI that these matters should be
evaluated only in the OATT Reform Proceeding. In Order No. 890, the
Commission directed transmission owners to use the ERO's Reliability
Standards development process to implement changes required in that
Final Rule.\277\
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\277\ Order No. 890 at P 196.
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795. Accordingly, the Commission approves Reliability Standard FAC-
013-1 as mandatory and enforceable, and, pursuant to section 215(d)(5)
of the FPA and Sec. 39.5(f) of our regulations, the Commission directs
the ERO to develop a modification to FAC-013-1 through the Reliability
Standards development process that makes it applicable to reliability
coordinators.
[[Page 16497]]
6. INT: Interchange Scheduling and Coordination
796. The Interchange Scheduling and Coordination (INT) group of
Reliability Standards addresses interchange transactions,\278\ which
occur when electricity is transmitted from a seller to a buyer across
the power grid. Specific information regarding each transaction must be
identified in an accompanying electronic label, known as a ``Tag'' or
``e-Tag'' which is used by affected reliability coordinators,
transmission service providers and balancing authorities to assess the
transaction for reliability impacts. Communication, submission,
assessment and approval of a Tag must be completed for reliability
consideration before implementation of the transaction.
---------------------------------------------------------------------------
\278\ The NERC glossary defines ``interchange'' as ``Energy
transfers that cross Balancing Authority boundaries.'' NERC Glossary
at 9.
---------------------------------------------------------------------------
a. Interchange Authority
797. The Version 1 INT Reliability Standards submitted with NERC's
August 28, 2006 supplemental filing include a new entity, the
interchange authority, which oversees interchange transactions and is
included as an applicable entity or referenced in the Requirements
sections of INT-005-1, INT-006-1, INT-007-1, INT-008-1, INT-009-1 and
INT-010-1.\279\ The Commission requested in the NOPR that NERC provide
additional information regarding the role of the interchange authority
so that the Commission could determine whether the interchange
authority is a user, owner or operator of the Bulk-Power System
required to comply with mandatory Reliability Standards.
---------------------------------------------------------------------------
\279\ The NERC Glossary defines an ``interchange authority'' as
``the 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.'' Id.
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i. Comments
798. ISO-NE states that it is unclear who the interchange authority
should be, how its tasks could be performed operationally and how the
interchange authority function relates to other reliability and market
functions. ISO-NE states that NERC has not yet fully incorporated the
concept of an interchange authority into its Functional Model and has
not provided a means for an entity to register as an interchange
authority under the Functional Model. Finally, ISO-NE states that NERC
must still create a process to allow the appropriate entities to
register as interchange authorities so that their status is clear to
all applicable entities, and it urges that approval of the Reliability
Standards that have the interchange authority as an applicable entity
be withheld until these issues are resolved.
799. APPA agrees that applicability of the Reliability Standards to
the interchange authority is confusing. However, APPA suggests the best
approach to the problem is for NERC to identify the source and sink
balancing authorities as the applicable entity in these Reliability
Standards until the Functional Model is revised to better specify the
status and responsibility of interchange authorities.
800. EEI observes that there is considerable confusion throughout
the industry regarding the registration process and the relationship
between registration and applicability of standards, with the
interchange authority being an example of that confusion. However, EEI
states it understands that the role of an interchange authority is
currently being addressed and revisions to the Functional Model are
currently moving through the approval process. If Version 3 of the
Functional Model is approved by the NERC Board, EEI believes it will
clarify that a sink balancing authority performing a Tag authority
service could serve as an interchange authority and this modification
would address the Commission's concern.
801. The CAISO suggests that it is premature to place any INT
Reliability Standards involving an interchange authority into effect
until more information is provided concerning the interchange
authority's role.
ii. Commission Determination
802. The NERC glossary definition of interchange authority
indicates that it is intended to provide essentially a quality control
function in verifying and approving interchange schedules and
communicating that information. Our understanding is that, in the
interim, sink and source balancing authorities will serve as
interchange authorities until the ERO has further clarified an
interchange authority's role and responsibility in the modification of
the Functional Model and in the registration process. The new
interchange authority function allows an entity other than a balancing
authority to perform this function in the future; the pre-existing INT-
001-1 Reliability Standard identified the balancing authority as the
responsible entity to perform this function. Any such entity should be
registered by the ERO in the ERO compliance registry, so that the
responsibility of an entity, other than a balancing authority, that
takes on this role in the future would be clear.
803. In short, there is sufficient clarity concerning the nature
and responsibilities of this function for it to be implemented at this
time. Withholding approval of INT Reliability Standards pending further
clarification on this matter would create an unnecessary gap in the
coverage of the Reliability Standards that potentially could threaten
the reliability of the Bulk-Power System.
b. Interchange Information (INT-001-2)
804. INT-001-1 seeks to ensure that interchange information is
submitted to the reliability analysis service identified by NERC.\280\
This Reliability Standard 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. The Requirements apply to all dynamic schedules, delivery from a
jointly owned generator and bilateral inadvertent interchange payback.
---------------------------------------------------------------------------
\280\ Currently, the reliability analysis service used by NERC
is the Interchange Distribution Calculator.
---------------------------------------------------------------------------
805. The Commission proposed in the NOPR 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 its regulations,
the Commission proposed to direct NERC to 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.\281\
---------------------------------------------------------------------------
\281\ This Requirement was included in INT-001-0 as Requirement
R1.2.
---------------------------------------------------------------------------
806. The Commission also noted in the NOPR that certain
Requirements of INT-001-0 that relate to the timing and content of e-
Tags had been deleted in the Version 1 Reliability Standard. NERC
indicated that these Requirements are business practices that would be
included in the next version of the NAESB Business Practices. The
Commission stated in the NOPR that NERC's explanation of this change
was acceptable and proposed to approve INT-001-1 with the deletion of
Requirements R1.1, R3, R4 and R5. However, the Commission also noted
that NAESB had not yet filed the e-Tagging requirements as part of its
[[Page 16498]]
business practices, and that if no such business practice has been
submitted at the time of the Final Rule, the Commission may reinstate
these Requirements in the Final Rule.
807. NERC submitted INT-001-2, which supersedes the Version 1
Reliability Standards, in its November 15, 2006 filing. INT-001-2 adds
Measures and Levels of Non-Compliance to the Version 0 Reliability
Standard. In this Final Rule, the Commission addresses INT-001-2, as
filed with the Commission on November 15, 2006.
i. Comments
808. APPA states that NERC's submission of INT-001-2 on November
15, 2006 has fulfilled the Commission's proposed directive to include
Measures and Levels of Non-Compliance in this Reliability Standard.
APPA also states that, while it does not oppose NERC consideration of
the Commission's proposed directive regarding the submission of
interchange information for all point-to-point transfers entirely
within a balancing authority area, it does not understand the
Commission's reliability concerns in this connection.
809. MidAmerican states that it favors the Commission's proposed
directive to NERC for a modification of the Reliability Standard as a
substantial improvement for reliability. Constellation supports this
proposal and states that the proposal, together with other initiatives,
such as OATT reform, represent additional steps to achieving not only
Bulk-Power System reliability, but also a reduction of undue
discrimination in transmission services.
810. NERC disagrees with the Commission's proposal to direct the
submission of interchange information on all point-to-point transfers
within a balancing area. NERC contends that this issue was discussed at
great length in the Reliability Standards development process and the
vast majority of commenters and voters agreed that such a requirement
would have no merit from a reliability perspective. It also states that
such data is not used today by the NERC interchange distribution
calculator for reliability.\282\ Finally, NERC concludes that while it
may be appropriate for this issue to be reconsidered in revisions to
the Reliability Standards, a Commission directive to include a
requirement that the collective expertise and the consensus of the
industry have determined to be unnecessary for reliability constitutes
``setting the standard.''
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\282\ The NERC glossary defines the interchange distribution
calculator as ``[t]he 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 9.
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811. LPPC agrees with the Commission that Requirements R1.1, R3, R4
and R5 are good business practices, and it states that for this reason
they should not be included in the Reliability Standards. These
business practices should more appropriately be contained in NAESB
standards, or perhaps the pro forma OATT.
812. ERCOT maintains that INT-001-1 is not appropriate for the
ERCOT region. ERCOT states that it is a single balancing authority. To
the extent that INT-001-1 requires tagging transfers within a single
balancing authority, it cannot be applied to ERCOT as written because
all point-to-point transfers within ERCOT are financial transactions
only. ERCOT notes that it tags transfers outside the ERCOT region.
813. Allegheny states that the requirement to tag point-to-point
transactions cannot be met in the PJM market where Tags are not used
when a transaction's source and sink are within the PJM footprint. Such
transactions are reported through the PJM eSchedule system, which
already provides adequate information for the PJM region to conduct
reliability and curtailment analyses. Allegheny states that there is no
reliability gap in the PJM market arising from this issue.
814. Santa Clara submits that LSEs should be applicable entities
under proposed revised INT-001-2 to ensure that they have adequate
notice of the requirements of this Reliability Standard. It states that
the actions of LSEs are implicated in Requirement R1 of this proposed
Reliability Standard.\283\
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\283\ INT-001-2 Requirement R1 provides that the LSE and
purchasing-selling entity shall ensure that arranged interchange is
submitted to the interchange authority.
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ii. Commission Determination
815. The Commission approves INT-001-2 as a mandatory and
enforceable Reliability Standard. In addition, we direct the ERO to
develop modifications to the Reliability Standard through the
Reliability Standards development process, as discussed below.
816. We agree with APPA that INT-001-2, submitted on November 15,
2006 includes Measures and Levels of Compliance, and we will not direct
any further action regarding Measures and Levels of Compliance at this
time.
817. MidAmerican and Constellation support the Commission's
proposal that this Reliability Standard include 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. The Commission
points out that unless these grandfathered and ``non-Order No. 888''
transfers are included in one of the INT Reliability Standards, they
might not be subject to appropriate curtailment as necessary due to
system conditions. Curtailments are determined using the interchange
distribution calculator. Unless transactions internal to a balancing
authority area are included in the calculator as we proposed, they are
not recognized by the calculator and may never be curtailed. For
instance, even if a transaction internal to a balancing authority area
is non-firm and some inter-balancing authority trades are firm, the
latter could be cut before the former, despite the curtailment
priorities in the Order No. 888 tariff. While we recognize that most
trades internal to a balancing authority area do not affect
interchange, some do, since electricity flows do not necessarily follow
the contract path.
818. In addition, e-Tagging of such transfers was previously
included in INT-001-0 and the Commission is aware that such transfers
are included in the e-Tagging logs. In short, the practice already
exists, but if this Requirement is removed from INT-001-2, no
Reliability Standard would require that such information be provided.
We therefore will adopt the directive we proposed in the NOPR and
direct the ERO to include a modification to INT-001-2 that 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.
819. The Commission agrees with ERCOT's conclusion that the
Reliability Standard does not apply to financial point-to-point
transfers within the ERCOT region. This interpretation is consistent
with the proposed INT Reliability Standards. Likewise, Allegheny's
views on tagging point-to-point transactions within the PJM market are
consistent with the proposed INT Reliability Standards.
820. With respect to Santa Clara's position that LSEs should be
applicable entities under the Reliability Standard, the Commission
notes that in situations where a LSE is securing energy from outside
the balancing authority to supply its end-use customers, it would
function as a purchasing-selling entity, as defined in the NERC
glossary, and would be included in the NERC registry
[[Page 16499]]
on that basis. This interpretation flows from the language of the
Reliability Standards, and the Commission does not perceive any
ambiguity in this connection. Nevertheless, the Commission directs the
ERO to consider Santa Clara's comments, and whether some more explicit
language would be useful, in the course of modifying INT-001-2 through
the Reliability Standards development process.
821. The Commission accepts NERC's explanation that Requirements
R1.1, R3, R4 and R5 of INT-001-0 that were deleted in INT-001-1 are
business practices. NAESB voluntarily filed ``Standards for Business
Practices and Communication Protocols for Public Utilities'' in Docket
No. RM05-5-000 on November 16, 2006. This filing contains wholesales
electric business practice standards that incorporate e-Tagging
requirements and is the subject of a separate rulemaking process that
is expected to result in rules that will become effective on or about
the same time as the Reliability Standard becomes mandatory.
822. Accordingly, the Commission approves Reliability Standard INT-
001-2 as mandatory and enforceable. In addition, the Commission directs
the ERO to develop a modification to INT-001-2 through its Reliability
Standards development process that 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.\284\
---------------------------------------------------------------------------
\284\ The Requirement was included in INT-001-0 as Requirement
R1.2.
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c. Regional Difference to INT-001-2 and INT-004-1: WECC Tagging Dynamic
Schedules and Inadvertent Payback
823. NERC proposed a regional difference that would exempt WECC
from requirements related to tagging dynamic schedules and inadvertent
payback. The Commission noted in the NOPR that WECC is developing a
tagging requirement for dynamic schedules. The Commission requested
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 an exemption would
cease when the tagging requirements become effective. The Commission
stated that it would not approve or remand an exemption until NERC
submits this information.\285\ Rather, we stated that we would consider
any regional differences contained in a proposed WECC tagging
requirement for dynamic schedules when submitted by NERC for Commission
review.
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\285\ To date, the Commission has not received the requested
information.
---------------------------------------------------------------------------
i. Comments
824. APPA agrees with the Commission's proposed course of action
addressing this regional difference.
825. Xcel requests that the Commission accept the proposed regional
difference; tagging requirements for dynamic schedules do not apply now
in WECC, and it would be burdensome and would provide little
reliability benefit to apply those requirements to WECC by June 2007.
The Commission therefore should approve the proposed variance for an
interim period until WECC's tagging requirements for dynamic schedules
are developed and approved.
ii. Commission Determination
826. The Commission stressed in Order No. 672 that uniformity of
Reliability Standards should be the goal and practice, ``the rule
rather than the exception.'' \286\ The Commission therefore stated in
the NOPR that the absence of a tagging requirement for dynamic
schedules in WECC is a matter of concern, and that for this reason it
could not approve or remand this regional difference without the
additional information it requested. To date the Commission has not
received this information. Of particular importance in this compliance
filing will be the ERO's demonstration that this practice is due to a
physical difference in the system or results in a more stringent
Reliability Standard. Without this information, we are unable to
address Xcel's comments further. The Commission therefore directs the
ERO to submit a filing within 90 days of the date of this order either
withdrawing this regional difference or providing additional
information.
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\286\ Order No. 672 at P 290.
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d. Regional Difference to INT-001-2 and INT-003-2: MISO Energy Flow
Information
827. NERC proposed a regional difference that would allow MISO to
provide market flow information in lieu of tagging intra-market flows
among its member balancing authorities; 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 affected. The waiver request text
includes a condition specifying that the ``Midwest ISO must provide
equivalent information to Reliability Authorities as would be extracted
from a transaction tag.'' The Commission proposed in the NOPR to
approve this regional difference. It explained there that, based on the
information provided by NERC, the proposed regional difference is
necessary to accommodate MISO's Commission-approved, multi-control area
energy market. Thus, the Commission stated it believed that the
regional difference is appropriate, because it is more stringent than
the continent-wide Reliability Standard and otherwise satisfies the
statutory standard for approval of a Reliability Standard.
i. Comments
828. APPA agrees with Commission's proposed course of action in
approving this regional difference.
ii. Commission Determination
829. The information received by the Commission demonstrates that
the proposed regional difference to INT-001-2 and INT-003-2, as filed
on November 15, 2006, is necessary to accommodate MISO's Commission-
approved, multi-control area energy market. The Commission concludes
that the regional difference is appropriate, because it is more
stringent than the continent-wide Reliability Standard and otherwise
satisfies the statutory standard for approval of a Reliability
Standard, and therefore approves it as mandatory and enforceable.
e. Interchange Transaction Implementation (INT-003-2)
830. The purpose of INT-003-1 is to ensure that balancing
authorities confirm interchange schedules with adjacent balancing
authorities before implementing the schedules in their area control
error equations. INT-003-1 contains a Requirement that focuses on
ensuring that a sending balancing authority confirms interchange
schedules with its receiving balancing authority before 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.
[[Page 16500]]
831. The Commission proposed in the NOPR to approve Reliability
Standard INT-003-1 as mandatory and enforceable. In addition the
Commission proposed to direct NERC to submit a modification to INT-003-
1 that includes Measures and Levels of Non-Compliance.
832. NERC filed INT-003-2 with the Commission on November 15, 2006.
This Reliability Standard supersedes the Version 1 Reliability Standard
INT-003-1 and adds Measures and Levels of Non-Compliance.
i. Comments
833. APPA states that INT-003-2 fulfills the Commission's proposed
directive to include Measures and Levels of Non-Compliance.
ii. Commission Determination
834. INT-003-1 serves an important purpose in requiring receiving
and sending balancing authorities to confirm and agree on interchange
schedules. With the addition of Measures and Levels of Non-Compliance,
INT-003-2 addresses the Commission's only reservation regarding this
Reliability Standard. Accordingly, the Commission approves Reliability
Standard INT-003-2, as filed with the Commission on November 15, 2006,
as mandatory and enforceable.
f. Regional Differences to INT-003-2: MISO/SPP Scheduling Agent and
MISO Enhanced Scheduling Agent
835. NERC proposed a regional difference that would provide MISO
and SPP with a variance from INT-003-1 to permit a market participant
to use a scheduling agent to prepare a transaction Tag on its
behalf.\287\ In addition, NERC proposed the MISO Enhanced Scheduling
Agent Waiver, which creates a variance from INT-003-1 for MISO that
permits an enhanced single point of contact scheduling agent.
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\287\ NERC proposed three regional differences for INT-003-1
that would apply to MISO. One proposed regional difference was
addressed in Reliability Standard INT-001-1. The remaining two are
discussed here.
---------------------------------------------------------------------------
836. The Commission proposed in the NOPR to approve these two
additional regional differences. The Commission explained that, based
on the information provided by NERC, the proposed regional differences
for this INT Reliability Standard would provide administrative
efficiency, and provide equal or greater amounts of information to the
appropriate entities as required in MISO's Commission-approved multi-
control area energy market. The NOPR stated that the regional
difference is appropriate because it is more stringent than the
continent-wide Reliability Standard and otherwise satisfies the
statutory standard for approval of a Reliability Standard.
i. Comments
837. APPA agrees with the Commission's proposed approval of these
regional differences.
838. FirstEnergy states that it would be helpful if NERC clarified
the function and effect of these waivers. FirstEnergy states that,
where a specific task will be performed by another entity on behalf of
the transferor, the transferor entity needs a delegation agreement,
whereas in transferring a responsibility, the transferor entity needs a
waiver. FirstEnergy states that currently balancing authorities are
held accountable by regional reliability organizations for those
functions the waivers transfer to the regional reliability
organization. FirstEnergy suggests that NERC should clarify that, under
these waivers, responsibility for complying with these Reliability
Standards should be transferred to the RTOs that actually perform the
tasks associated with these requirements.
ii. Commission Determination
839. These two variances from INT-003-2, as filed with the
Commission on November 15, 2006, permit a market participant to use a
scheduling agent to prepare a transaction tag on its behalf, providing
administrative efficiency and providing equal or greater amounts of
information to the appropriate entities as required in MISO's
Commission-approved multi-control area energy market. This regional
difference is appropriate because it is more stringent than the
continent-wide Reliability Standard and otherwise satisfies the
statutory standard for approval of a Reliability Standard. The
Commission therefore approves the MISO/SPP Scheduling Agent Waiver and
the MISO Enhanced Scheduling Agent Waiver as mandatory and enforceable
regional differences to INT-003-2.
840. FirstEnergy may raise its suggestions in the Reliability
Standards development process. However, we find that FirstEnergy's
suggestion does not affect our decision to approve these two regional
differences.
g. Dynamic Interchange Transaction Modifications (INT-004-1)
841. INT-004-1 seeks 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 Tags for dynamic schedules.
842. In the NOPR, the Commission proposed to approve Reliability
Standard INT-004-1 as mandatory and enforceable. The Commission also
proposed to direct NERC to submit a modification to INT-004-1 that
includes Levels of Non-Compliance.
i. Comments
843. APPA agrees with the Commission that INT-004-1 can be approved
as a mandatory and enforceable Reliability Standard. However, it
suggests that the missing Levels of Non-Compliance should be developed
and submitted for Commission approval before penalties are levied for
violations.
ii. Commission Determination
844. As explained in the NOPR, 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.
Further, the Requirements set forth in INT-004-1 are sufficiently clear
and objective to provide guidance for compliance. Accordingly, the
Commission approves Reliability Standard INT-004-1 as mandatory and
enforceable. In addition, the Commission directs the ERO to consider
adding these Measures and Levels of Non-Compliance to the Reliability
Standard.
h. Interchange Authority Distributes Arranged Interchange (INT-005-1)
845. INT-005-1 seeks to ensure the implementation of interchange
between source and sink balancing authorities and that interchange
information is distributed by an interchange authority to the relevant
entities for reliability assessments.
846. The Commission proposed in the NOPR to approve Reliability
Standard INT-005-1 as mandatory and enforceable. The Commission also
proposed to direct NERC to submit a modification to INT-005-1 that
includes Levels of Non-Compliance. Further, the Commission noted that
INT-005-1 is applicable to the ``interchange authority'' and requested
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.
[[Page 16501]]
i. Comments
847. Comments on the interchange authority have been discussed
above under the heading ``INT Reliability Standards General Issues.''
No other comments on INT-005-1 have been submitted.
ii. Commission Determination
848. The Commission has set forth above its analysis and conclusion
on interchange authorities. Our understanding is that, in the interim,
source and sink balancing authorities will serve as interchange
authorities until the ERO has clarified the role and responsibility of
an interchange authority in the modification of the Functional Model
and in the registration process.
849. The Commission is satisfied that the Requirements of INT-005-1
are appropriate to ensure that interchange information is distributed
timely and available for reliability assessment. Accordingly, the
Commission approves Reliability Standard INT-005-1 as mandatory and
enforceable. In addition, the Commission directs the ERO to consider
adding additional Measures and Levels of Non-Compliance to the
Reliability Standard.
i. Response to Interchange Authority (INT-006-1)
850. INT-006-1 applies to balancing authorities and transmission
service providers, and requires these entities to evaluate the energy
profile and ramp rate of generation that supports interchange
transactions in response to a request from an interchange authority to
change the status of an interchange from an arranged interchange
transaction to a confirmed interchange.
851. The Commission proposed in the NOPR to approve Reliability
Standard INT-006-1 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to 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 before
implementation.
i. Comments
852. APPA agrees that INT-006-1 is sufficient for approval as a
mandatory and enforceable reliability standard. However, APPA states
that the Commission should merely instruct NERC to respond to the
Commission's concerns and refrain from directing NERC to make specific
changes to the Reliability Standard; APPA states that while the changes
the Commission proposes may be appropriate, it should be left to NERC's
expertise and the Reliability Standards development process to address
the Commission's concerns.
853. FirstEnergy agrees that it is appropriate for the reliability
coordinator to be included in the applicability section. However, it
argues that it is impracticable in large organized markets, such as
those of MISO and PJM, for a local entity, such as a transmission
operator, to review wide-area transactions, and it does not improve
reliability to do so. Transactions occurring totally within the market
operation are provided as part of network service net scheduled
interchange.
854. EEI states that the ``wide-area reliability impact'' review
envisioned by the Commission, which involves review of the composite
energy interchange transactions, probably already takes place under
Reliability Standards INT-005 through INT-009 in a cost-effective
manner. EEI explains that since most transactions submitted by
wholesale markets to the transactions tagging process span multiple
hours with varying sizes (in MW), and are often submitted days before
transaction start times, the wide-area review consists of ensuring that
sufficient generator ramping capability exists, as well as examining
for limits on transfer capabilities. This review is generally
considered sufficient to the extent that analyses are taking place on
the basis of projected system conditions. EEI suggests that the
Commission-proposed review and validation of composite energy
interchange transactions by reliability coordinators might be more
effectively addressed through ``near real-time'' system review. It
explains that, at this time, the broad range of system condition
parameters is better known, and the reliability coordinators can make
use of the TLR process to maintain system reliability.
855. Entergy disagrees with the Commission's proposed
modifications. It contends that they will require substantial changes
to the tagging specifications. Entergy believes that the Commission's
concerns may already be addressed by Reliability Standards INT-005
through INT-009.
856. MISO believes the Reliability Standards and e-Tag
specifications already require reliability entities to evaluate and
approve e-Tags. It questions the value of specifying reliability
coordinators and transmission operators as applicable entities because
their responsibilities are already laid out in the Reliability
Standards.
857. Northern Indiana contends that the NOPR's discussion of INT-
006-1 is unclear and confusing. It states that it does not understand
what the Commission means by ``validate'' when the Commission proposes
that reliability coordinators and transmission operators review and
validate composite arranged interchanges. Northern Indiana also
questions whether both reliability coordinators and transmission
operators would be required to validate and approve the Tags and what
the basis for approval would be. It questions what falls within the
term ``potential detrimental reliability impact,'' what happens if a
Tag is not validated within 20 minutes to the hour, and whether all
schedules are canceled outright or passively approved.
858. TVA suggests that the term ``composite Tag'' should be defined
as part of the proposed modifications. CAISO also questions the meaning
of ``composite Tag'' and seeks clarification on that issue. TVA notes
that depending on the type of reliability analysis required to validate
a ``composite Tag,'' it may prove impractical to conduct this
evaluation for hourly transactions.
859. CAISO states that neither NERC nor the Commission has
identified a deficiency in the current interchange reliability
assessment process or a pressing reliability need for this Reliability
Standard. CAISO also has concerns about meeting the Commission-proposed
directives regarding INT-006-1 since reliability coordinators and
transmission operators within the Western Interconnection currently do
not have a common database from which to draw the information needed to
review composite transactions from a wide-area reliability viewpoint.
CAISO requests the Commission to consider whether the Western
Interconnection should comply with these proposed Requirements at all
or whether a transition period is appropriate.
ii. Commission Determination
860. The Commission approves INT-006-1 as mandatory and
enforceable. In addition, we direct that NERC develop modifications to
the Reliability Standard, as discussed below.
861. The Commission remains convinced that a proactive approach is
superior to a reactive approach in maintaining system reliability.
While EEI and Entergy claim that reliability
[[Page 16502]]
coordinators and transmission operators' involvement in reliability
reviews of interchange transactions are covered in INT-005 through INT-
010, and MISO claims that such review is covered in other Reliability
Standards, we note the following: References to reliability coordinator
and transmission operator involvement are virtually absent from the INT
Reliability Standards. One finds such references only in Requirement R2
of INT-010, which deals with interchange coordination exemptions, and
there the involvement of reliability coordinators is restricted to
situations that involve current or imminent reliability-related reasons
for action. We cannot find any Requirements in the remaining INT
Reliability Standards that require a wide-area reliability assessment,
regardless of the time periods, by a reliability coordinator; wide-area
reliability assessment, moreover, can only be carried out by
reliability coordinators.
862. With respect to MISO's comment on the value of applying the
Reliability Standard to reliability coordinators and transmission
operators given that the Reliability Standards and the e-Tag
specification already require evaluation and active approval of
reliability entities on e-Tags, we note that none of the INT
Reliability Standards have those requirements and that the e-Tag
specification is not part of the mandatory Reliability Standards. Like
reliability coordinators who are responsible for reliable operation of
entire reliability coordinator areas, a transmission operator is the
reliability entity responsible for its local area operations.
Interchange transactions would be likely to reduce system reliability
if those transactions are not reviewed and approved by the appropriate
reliability entities before implementation.
863. With respect to the question raised by TVA and CAISO on the
definition of ``composite Tags,'' we expressed our reliability concerns
in the NOPR and explained that reliability coordinators and
transmission operators should review composite energy interchange
transaction information (composite Tags) for wide-area reliability
impact. In addition, we stated that 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 before
implementation.\288\ While we did not require a specific notification
time prior to actual transactions, this proactive approach should
promote system reliability.
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\288\ NOPR at P 219.
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864. We agree with FirstEnergy that it is appropriate to include
reliability coordinators as applicable entities for purposes of
conducting wide-area reliability assessments; in large organized
markets transmission operators may not be appropriate for this purpose
because they do not have a wide-area view.
865. While we did not address review time frames in the NOPR, we
are in general agreement with EEI's suggestion that ``near-real time''
system review by reliability coordinators may be more practical, while
still being efficient and effective in achieving reliability goals. A
proactive approach, i.e. one that involves reliability coordinators in
a way that permits them to make wide-area assessments of composite
interchange transactions for purposes of evaluating reliability impact,
including identifying potential IROL violations and mitigating them
using TLR procedures before they become actual IROL violations, is far
superior to a reactive approach, i.e., one that brings reliability
coordinators in after the fact to invoke TLR procedures to avoid an
IROL violation or other operating actions to extricate the system from
reliability problems such as an actual IROL violation.
866. The Commission stated in Order No. 672 that it expected
entities to use the Reliability Standards development process to
address their concerns about a Reliability Standard. With respect to
CAISO's request that the Commission consider whether the Western
Interconnection needs to comply with these Requirements at all or
whether a transition period is appropriate, since CAISO did not raise
either concern in the Reliability Standards development process, and
others in the Western Interconnection have not raised a similar
concern, CAISO should raise this issue in the Reliability Standards
development process in the first instance. Reliability Standard INT-
006-1 will apply to CAISO.
867. Accordingly, the Commission approves Reliability Standard INT-
006-1 as mandatory and enforceable. In addition, the Commission directs
the ERO to develop a modification to INT-006-1 through the Reliability
Standards development process that: (1) Makes it applicable to
reliability coordinators and transmission operators and (2) requires
reliability coordinators and transmission operators to review energy
interchange transactions from the wide-area and local area reliability
viewpoints respectively and, where their review indicates a potential
detrimental reliability impact, communicate to the sink balancing
authorities necessary transaction modifications before implementation.
We also direct that the ERO consider the suggestions made by EEI and
TVA and address the questions raised by Entergy and Northern Indiana in
the course of the Reliability Standards development process.
j. Interchange Confirmation (INT-007-1)
868. Reliability Standard INT-007-1 requires that before changing
the status of submitted arranged interchanges to confirmed
interchanges, the interchange authority must verify that the submitted
arranged interchanges are valid and complete with relevant information
and approvals from the balancing authorities and transmission service
providers. The Commission proposed in the NOPR to approve INT-007-1 as
mandatory and enforceable.
i. Comments
869. APPA agrees with the Commission that INT-007-1 is sufficient
for approval as a mandatory and enforceable Reliability Standard,
subject to NERC's plans for the registration of entities as interchange
authorities.
ii. Commission Determination
870. The Commission approves Reliability Standard INT-007-1 as
mandatory and enforceable. The Commission has set forth above its
analysis and conclusion on interchange authorities. Our understanding
is that in the interim source and sink balancing authorities will serve
as interchange authorities until the ERO has clarified the role and
responsibility of an interchange authority in the modification of
Functional Model and in the registration process.
k. Interchange Authority Distribution of Information (INT-008-1)
871. 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. The Commission proposed
in the NOPR to approve INT-008-1 as mandatory and enforceable.
i. Comments
872. APPA agrees with the Commission that INT-008-1 is sufficient
for approval as a mandatory and enforceable Reliability Standard,
[[Page 16503]]
subject to NERC's plans for the registration of entities as interchange
authorities. It suggests that NERC should clarify which reliability
entities have the responsibility for ensuring that interchange
information is coordinated between the source and sink balancing
authorities before implementing the Reliability Standard. APPA also
states that NERC should modify this Reliability Standard to make clear
what entities it in fact would apply to.
ii. Commission Determination
873. The Commission approves Reliability Standard INT-008-1 as
mandatory and enforceable. The Commission has set forth above its
analysis and conclusion on interchange authorities. Our understanding
is that a source and sink balancing authority will serve as the
interchange authority until the ERO has clarified the role and
responsibility of an interchange authority in the modification of the
Functional Model and in the registration process. Finally, we direct
the ERO to consider APPA's suggestions in the Reliability Standards
development process.
l. Implementation of Interchange (INT-009-1)
874. Reliability Standard INT-009-1 seeks to ensure that the
implementation of an interchange between source and sink balancing
authorities is coordinated by an interchange authority. The Commission
proposed in the NOPR to approve INT-009-1 as mandatory and enforceable.
i. Comments
875. APPA agrees with the Commission that INT-009-1 is sufficient
for approval as a mandatory and enforceable Reliability Standard,
subject to NERC's plans for the registration of entities as interchange
authorities. It suggests that NERC modify its Functional Model to
clarify which reliability entities have the responsibility for ensuring
proper implementation of interchange transactions that have received
reliability assessments. APPA also suggests that NERC modify this
Reliability Standard to make clear what entities it in fact would apply
to.
ii. Commission Determination
876. The Commission approves Reliability Standard INT-009-1 as
mandatory and enforceable. The Commission has set forth above its
analysis and conclusion on interchange authorities. Our understanding
is that a source and sink balancing authority will serve as the
interchange authority until the ERO has clarified the role and
responsibility of an interchange authority in the modification of the
Functional Model and in the registration process. Finally, we direct
the ERO to consider APPA's suggestions concerning this Reliability
Standard in the Reliability Standards development process.
m. Interchange Exemptions (INT-010-1)
877. INT-010-1 allows reliability entities to initiate or modify
certain types of interchange schedules under abnormal operating
conditions and to be exempt from compliance with other INT Reliability
Standards.
878. The Commission explained in the NOPR that 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. The Commission interpreted these current
or imminent reliability-related reasons as not including actual IROL
violations, since they require immediate action so that the system can
be returned to a secure operating state as soon as possible and no
longer than 30 minutes after a reliability-related system
interruption--a period that is much shorter than the time that is
expected to be required for new or modified transactions to be
implemented.
879. The Commission proposed to approve INT-010-1, interpreted as
set forth above, as mandatory and enforceable.
i. Comments
880. Northern Indiana supports the Commission's interpretation of
INT-010-1, but it requests that the Reliability Standard be modified to
explicitly state that it does not include actual IROL violations.
881. ISO-NE supports Commission approval of INT-010-1, but does not
share the Commission's concerns regarding the initiation or
modification of interchange schedules to address SOL or IROL
violations. It states that interchange schedules can in certain
circumstances provide an additional effective tool to help prevent an
SOL and IROL violation. While ISO-NE recognizes that other tools may in
certain circumstances be more effective, it states that this neither
diminishes the value nor precludes the use of the tools contained in
INT-010-1. ISO-NE also notes that section 2.4 of INT-010-1, which
describes Level 4 Non-Compliance, should be edited to state that
``[t]here shall be a level four non-compliance * * *.`` instead of
``[t]here shall be a level three non-compliance * * *.''
882. APPA agrees with the Commission that INT-010-1 is sufficient
for approval as a mandatory and enforceable Reliability Standard, but
APPA does not agree with the Commission's interpretation of the
Reliability Standard. APPA explains that the stated purpose of INT-010-
1 is to allow certain types of interchange schedules to be initiated or
modified by reliability entities and to be exempt from compliance with
other interchange standards under abnormal operating conditions. This
Reliability Standard in effect authorizes reliability coordinators to
direct, and balancing authorities to take, remedial actions to adjust
interchange schedules immediately and then document these actions after
the fact. INT-010-1 thus provides the emergency waiver from other INT
Reliability Standards that makes adjusting interchange schedules the
appropriate response to a SOL or IROL. APPA states that the
Commission's proposed interpretation therefore should not be adopted.
883. EEI cautions against adopting the Commission's interpretation
of INT-010-1. EEI believes that the existing standard meets the
Commission's expectation, i.e., permitting and encouraging immediate
action to alleviate an SOL or IROL. EEI explains that without INT-010-
1, all interchange scheduling and schedule modifications would go
through the normal process contained in INT-005 through INT-009. Only
INT-010 would allow a balancing authority to make an immediate
interchange action without obtaining a Tag. Within 60 minutes of the
action, the balancing authority would follow up with the necessary
documentation and carry forward the action, if necessary. In the
absence of INT-010-1, a balancing authority taking such action would be
in violation of INT-009 for failing to comply with the normal process
requirements.
884. EEI notes by way of example that, to relieve an SOL or IROL, a
reliability coordinator requires immediate offsetting changes in the
net scheduled interchange of ACE equations of source and sink balancing
authorities. Within 60 minutes following the action, the reliability
authority directs the balancing authority to reflect the schedule
change event using an arranged interchange. The tagging activity
ensures coordination going forward and provides a written record. All
of this takes place after the operational tasks pertaining to the
action to alleviate the SOL or IROL,
[[Page 16504]]
consistent with Commission expectations.
ii. Commission Determination
885. For the reasons and interpretation noted in the NOPR, the
Commission approves INT-010-1 as mandatory and enforceable.
886. The Commission believes that our interpretation of INT-010-1
is consistent with the way APPA and EEI understand the Reliability
Standards. The Commission believes that making a modification to an
existing interchange schedule on paper for current or imminent
reliability-related situations involving actual IROL violations is
ineffective because its implementation usually takes much longer than
the 30-minute period that is allowed in the relevant IRO or TOP
Reliability Standards. However, the Commission interprets INT-010-1 as
allowing the actual physical transaction to be modified to alleviate an
IROL event without first documenting the modification. The interchange
schedule would then be modified after the fact to document the physical
actions taken.
887. With regard to ISO-NE's statement that interchange schedules
can, in certain circumstances, provide an additional effective tool to
help prevent SOL and IROL violations while other tools may, in certain
circumstances, be more effective, the Commission clarifies that our
concern is related to using interchange schedules to address actual
IROL violations. We have no concern in using this as a tool help
prevent potential SOL and IROL violations as asserted by ISO-NE. We
further note that the phrase in Requirements R2 and R3 ``current or
imminent reliability-related reasons'' can be interpreted as potential
or actual IROL violations set forth in the comments from Northern
Indiana, ISO-NE, APPA and EEI, and therefore modifications to INT-010-1
are needed.
888. Accordingly, the Commission approves Reliability Standard INT-
010-1 as mandatory and enforceable. In addition, we adopt the
interpretation set forth in the NOPR that these current or imminent
reliability-related reasons do not include actual IROL violations,
since 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 after a reliability-related system interruption--a
period that is much shorter than the time that is expected to be
required for new or modified transactions to be implemented. Finally,
we direct the ERO to consider Northern Indiana and ISO-NE's suggestions
in the Reliability Standards development process.
7. IRO: Interconnection Reliability Operations and Coordination
889. The Interconnection Reliability Operations and Coordination
(IRO) group of Reliability Standards detail the responsibilities and
authorities of a reliability coordinator.\289\ The 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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\289\ According to the NERC glossary, at 15, 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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a. Reliability Coordination--Responsibilities and Authorities (IRO-001-
1)
890. IRO-001-1 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.
891. In November 2006, NERC submitted IRO-001-1, which includes
Measures and Levels of Non-Compliance.\290\ In addition, while the
Version 0 Reliability Standard applied to reliability coordinators and
regional reliability organizations, IRO-001-1 would in addition apply
to transmission operators, balancing authorities, generator operators,
transmission service providers, LSEs and purchasing-selling entities.
The Version 1 Reliability Standard does not modify or add any
Requirements, and it appears that the change in applicability
corresponds to existing Requirement R8, which provides that
transmission operators, balancing authorities, generator operators,
transmission service providers, LSEs and purchasing-selling entities
``shall comply with Reliability Coordinator directives unless such
actions would violate safety, equipment, or regulatory or statutory
requirements.''
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\290\ IRO-001-1 supercedes the Version 0 Reliability Standard.
In this Final Rule, we review the November version, IRO-001-1.
---------------------------------------------------------------------------
892. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed to direct NERC to 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.
i. Comments
893. APPA supports the approval of the Reliability Standard but
expresses concern that the Version 1 standard does not include Measures
that correspond to Requirements R2 and R9. APPA emphasizes the need for
Measures corresponding to Requirement R9, which requires the
reliability coordinator to act in the interests of reliability for the
overall reliability coordinator area and the Interconnection before the
interests of any other entity. APPA supports Requirement R8 with the
extended applicability, provided that applicability is determined by
reference to the NERC compliance registry. APPA agrees that the
regional reliability organization should be eliminated as an applicable
entity and suggests it be replaced with Regional Entities.
894. FirstEnergy suggests that NERC clarify whether Requirement R8,
which requires entities to comply with a reliability coordinator
directive ``unless such actions would violate safety, equipment or
regulatory or statutory requirements,'' refers to personnel safety,
equipment safety or both. In addition, it suggests the establishment of
a chain of command so that, for example, if a generator receives
conflicting instructions from a balancing authority and a transmission
operator, it can determine which instruction governs.
895. Requirement R3 provides that a reliability coordinator ``shall
have clear decision-making authority to act and direct actions to be
taken'' by applicable entities to ``preserve the integrity and
reliability of the Bulk Electric System and these actions shall be
taken without delay but no longer than 30 minutes.'' Santa Clara
contends that some actions would require driving to a remote site and
therefore, mandating completion of the required action within 30
minutes would be unreasonable. Thus, it recommends that NERC modify
Requirement R3 to provide that ``actions shall commence without delay,
but in any event shall commence within 30 minutes.''
896. California Cogeneration comments that the Reliability Standard
fails to address the operational limitations of QFs because they have
contractual obligations to provide thermal energy to their industrial
hosts.
[[Page 16505]]
It contends that a QF can be directed to change operations only in the
case of a system emergency, pursuant to 18 CFR 292.307.
ii. Commission Determination
897. In the NOPR, the Commission proposed to approve the
Reliability Standard as mandatory and enforceable. In addition, as a
separate action under section 215(d)(5), the NOPR proposed to direct
the ERO to develop modifications to Requirement R1 \291\ to substitute
``Regional Entity'' for ``regional reliability organization'' and
reflect NERC's Rules of Procedure for registering, certifying and
verifying entities, including reliability coordinators. Commenters do
not raise any concerns regarding the proposed action. Accordingly, for
the reasons stated in the NOPR, the Commission approves IRO-001-1 as
mandatory and enforceable. In addition, for the reasons discussed in
the NOPR, the Commission directs the ERO to develop modifications to
the Reliability Standard through the Reliability Standards development
process that reflect the process set forth in the NERC Rules of
Procedures and eliminate the regional reliability organization as an
applicable entity.\292\
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\291\ Requirement R1 of IRO-001-1 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. See NOPR at P 506.
\292\ See NOPR at P 505-06.
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898. While APPA, FirstEnergy and California Cogeneration suggest
possible changes to IRO-001-1, they do not suggest that the proposed
Reliability Standard should not be approved. The ERO should consider
the commenters' suggestions when modifying the Reliability Standard
pursuant to its Reliability Standards development process. Further, the
Commission directs the ERO to consider adding Measures and Levels of
Non-Compliance in the Reliability Standard as requested by APPA.
899. However, we disagree with Santa Clara's suggested change
regarding the 30-minute limit to implement a corrective control action
in Requirement R3. When system integrity or reliability is jeopardized,
e.g., exceeding IROLs or SOLs, the relevant reliability entities must
take corrective control actions to return the system to a secure and
reliable state as soon as possible and in no longer than 30 minutes.
This is important to satisfy the relevant Reliability Standards such as
IRO-005-0 and TOP-004-0 to minimize the amount of time the system
operates in an insecure mode and is vulnerable to cascading outages.
b. Reliability Coordination--Facilities (IRO-002-1)
900. IRO-002-1 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, to act in addressing real-time emergency conditions
and to control analysis tools.\293\
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\293\ In its November 15, 2006, filing, NERC submitted IRO-002-
1, which supercedes the Version 0 Reliability Standard. IRO-002-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, IRO-002-1.
---------------------------------------------------------------------------
901. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed to direct NERC to submit a
modification 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.
i. Comments
902. Dominion agrees with the proposal to require a minimum set of
tools for reliability coordinators, explaining that such specificity is
needed to ensure that proactive efforts to maintain reliability are
being continuously pursued. According to Dominion, a general
requirement for ``adequate'' tools is insufficient and the proposal to
modify IRO-002-1 is appropriate since it will ensure that operators
have a minimum set of tools with which to perform their duties.
903. In contrast, both APPA and LPPC ask the Commission to reject
the proposal to require a minimum set of tools because flexibility is
needed to allow change as technology improves over time. LPPC states
that the Commission should, instead, require a listing of capabilities
that is not tied to a particular product or tool. APPA contends that,
because the Measures now require the reliability coordinator to provide
specifications to the Regional Entity to be in compliance, the Regional
Entity will set the minimum standards for reliability tools. Further,
according to APPA, setting a minimum requirement would establish a
``lowest common denominator'' that might prove counterproductive.
904. MRO states that IRO-002-0 is another Reliability Standard for
which it will be difficult to identify Measures and Levels of Non-
Compliance because the Requirements include terms like ``adequate,''
``potential,'' ``could result'' and ``as required.''
ii. Commission Determination
905. NERC's November 2006 revision to the Reliability Standard
satisfies the proposal to include Measures and Levels of Non-
Compliance. While MRO comments that it will be difficult to identify
Measures and Levels of Non-Compliance, it does not provide any specific
suggestions for changes to NERC's proposal.
906. Further, consistent with the NOPR, the Commission directs the
ERO to modify IRO-002-1 to require a minimum set of tools that must be
made available to the reliability coordinator. We believe that this
requirement will ensure that a reliability coordinator has the tools it
needs to perform its functions. Further, as noted by Dominion, such a
requirement promotes a more proactive approach to maintaining
reliability.
907. With respect to the concerns of APPA and LPPC, the Commission
clarifies that the Commission's intent is to have the ERO develop a
requirement that identifies capabilities, not actual tools or products.
The Commission agrees that the latter approach is not appropriate as a
particular product could become obsolete and technology improves over
time. We disagree with APPA that our concern is addressed by the new
Measures as they neither specify a minimum set of capabilities nor
require any uniformity among reliability coordinators or Regional
Entities. We do not believe that the identification of minimum
capabilities translates to ``lowest common denominator'' as suggested
by APPA. If the Reliability Standards development process results in
developing a ``lowest common denominator'' Reliability Standard that is
geared toward guaranteeing compliance and avoiding penalties as opposed
to ensuring reliability, the Commission could remand such a Reliability
Standard.\294\
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\294\ See Order No. 672 at P 329.
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908. We disagree with MRO that it will be difficult to identify
Measures and Levels of Non-Compliance since the Requirements include
terms like ``adequate,'' ``potential,'' ``could result'' and ``as
required.'' Many tariffs on file with the Commission do not specify
every compliance detail, but rather provide some level of discretion as
necessary to carry out a particular act. This does not mean the tariffs
are unenforceable; rather, it means that, if a
[[Page 16506]]
dispute arises over compliance and there is a legitimate ambiguity
regarding a particular fact or circumstance, that ambiguity can be
taken into account in the exercise of the Commission's enforcement
discretion.
909. As we stated in the NOPR,\295\ Reliability Standard IRO-002-1
serves an important purpose in ensuring that reliability coordinators
have the information, tools and capabilities to perform their
functions. The Measures and Levels of Non-Compliance submitted by NERC
further enhance the Reliability Standard. Accordingly, the Commission
approves Reliability Standard IRO-002-1 as mandatory and enforceable.
In addition we direct the ERO to develop a modification to IRO-002-1
through the Reliability Standards development process that requires a
minimum set of tools that should be made available to reliability
coordinators.
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\295\ NOPR at P 511.
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c. Reliability Coordination--Wide Area View (IRO-003-2)
910. The purpose of IRO-003-2 is for a reliability coordinator to
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.\296\
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\296\ In its November 15, 2006, filing, NERC submitted IRO-003-
2, which supersedes the Version 0 Reliability Standard. IRO-003-2
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, IRO-003-2.
---------------------------------------------------------------------------
911. In the NOPR, the Commission proposed to approve the
Reliability Standard 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 proposed to direct NERC to submit a
modification 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.
i. Comments
912. APPA agrees that IRO-003-2 is sufficient for approval as a
mandatory and enforceable Reliability Standard. However, APPA suggests
that, instead of merely including criteria to define critical
facilities as proposed, NERC and each Regional Entity should establish,
document, use and make transparent the methodology, data and procedures
they use to determine ``critical facilities.''
913. Entergy agrees with the need for the criteria, but cautions
that it must be flexible enough to allow for changing conditions
experienced in real-time operations. Xcel notes that the term
``critical facilities'' is not defined and suggests that the
Reliability Standard not be approved until the term is defined.
ii. Commission Determination
914. For the reasons stated in the NOPR,\297\ the Commission
approves proposed Reliability Standard IRO-003-2 as mandatory and
enforceable. NERC's November 2006 revision to the Reliability Standard
satisfies the proposal to include Measures and Levels of Non-
Compliance.
---------------------------------------------------------------------------
\297\ See NOPR at P 519.
---------------------------------------------------------------------------
915. Further, pursuant to section 215(d)(5) of the FPA and Sec.
39.5(f) of our regulations, we adopt in the Final Rule the proposal to
direct that the ERO develop a modification to the Reliability Standard
through the Reliability Standards development process to create
criteria to define the term ``critical facilities'' in a reliability
coordinator's area and its adjacent systems. In developing the required
modification, the ERO should consider the suggestions of APPA, Entergy
and Xcel.
d. Reliability Coordination--Operations Planning (IRO-004-1)
916. The purpose of IRO-004-1 is to require each reliability
coordinator to 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.
917. In the NOPR, the Commission proposed 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 proposed to direct NERC to 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.
i. Comments
918. APPA agrees that IRO-004-1 is sufficient for approval as a
mandatory Reliability Standard and that the Requirements are
sufficiently clear and objective to provide a basis for issuing a
remedial action directive. However, it contends that many Requirements
lack Measures and Levels of Non-Compliance, and the ERO and Regional
Entities should not assess penalties until additional Measures and
Levels of Non-Compliance are developed.
919. Entergy agrees that a mitigation plan for potential operating
problems identified in the next-day analysis may be an appropriate
requirement, but cautions that it would be inappropriate to penalize an
entity that chooses an alternate mitigation strategy when the issues
arise in real time based on system conditions prevalent at that time.
920. APPA, in contrast, disagrees with the proposed directive to
identify effective control actions in the next-day analysis. It
contends that real-time conditions are seldom the same as predicted in
the day-ahead schedule, and state estimators using real-time operating
conditions are much more accurate than analyses based on day-ahead
schedules.
921. FirstEnergy contends that IRO-004-1 should require a day-ahead
planning process and reflect activities inherent within a market
operation.
922. Northern Indiana contends that the Commission's proposed
directive is unclear. It asks whether the Commission is requiring the
reliability coordinator to secure the system to an N-2 state, rather
than an N-1 state within the next-day planning analysis. It contends
that currently the Reliability Standard is N-1, and requests
clarification that the Commission did not intend to mandate an increase
in security from N-1 to N-2 in the NOPR.
923. California PUC agrees that there is merit in requiring system
operators to assess the outlook for the following day, but nevertheless
is concerned with the Commission's proposed directive. Its main concern
is that the list of identified control actions can be too long or too
generic to be effective to address the myriad potential system
contingencies that could arise on the next day.
924. California Cogeneration states that the proposed Reliability
Standard allows reliability coordinators to require data on gross load
and generation behind the site boundary meter, which is contrary to a
prior Commission order.\298\
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\298\ California Independent System Operator Corp., 96 FERC ]
63,015 at 7 (2001). It states in part ``The intent of the
Commission's directive was to remove the requirement to provide any
behind-the-meter information, whether on generation or load.''
---------------------------------------------------------------------------
ii. Commission Determination
925. For the reasons stated in the NOPR,\299\ the Commission
approves proposed Reliability Standard IRO-004-1 as mandatory and
enforceable. In
[[Page 16507]]
addition, the Commission directs the ERO to develop modifications to
the Reliability Standard, as discussed below.
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\299\ See NOPR at P 529.
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926. We agree with Entergy that system operators must make their
decision to use the most effective control action based on the
prevailing system conditions, to return the system to a secure state
following a contingency. Therefore, the chosen control action may be
different than those identified in next-day operations planning. We
reiterate that our intent is to require a comprehensive next-day
operations planning study that includes identification of effective
solutions to aid system operators in real-time operations.
927. We disagree with APPA's comment that day-ahead planning to
identify effective control actions would not enhance system reliability
because we believe this is also the intent of the ERO for including
such a Requirement in this Reliability Standard.\300\ Our proposed
directive is to augment the Requirement that the plans to alleviate SOL
and IROL violations are assessed to ensure that the control actions can
be implemented and effective within 30 minutes after a contingency.
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\300\ IRO-004-1 Purpose Statement states in part ``Plans must be
developed to alleviate SOL and IROL violations.''
---------------------------------------------------------------------------
928. We agree with APPA that state estimators and real-time
contingency analyses using real-time operating conditions produce more
accurate study results compared to those from next-day operations
planning analyses that are based on day-ahead schedules and forecast
conditions. However, we remain convinced that a proactive approach that
includes identification of effective operating solutions to deal with
contingencies is far superior to a reactive approach that identifies
solutions when the system conditions prevail in real-time operations.
The former can identify solutions that may not be otherwise available
to the system operators--e.g. certain planned generation or
transmission outages are approved conditional upon re-affirmation prior
to their removal from service or a short recall time subject to certain
system conditions developing in real-time operations.
929. We disagree with FirstEnergy that IRO-004-1 should include the
day-ahead planning process and reflect activities inherent in a market
operation because day-ahead planning includes financial activities that
may not occur in real-time. The Commission believes that, for
reliability purposes, the simulation should include only what will
actually occur.
930. The proposed Reliability Standards IRO-005-1 and TOP-004-0
require that in the event of an IROL violation, i.e. power flow on an
interface exceeding its IROL, the system must be returned to a secure
state within 30 minutes regardless of the cause of the violation, so
that the system is once again capable of withstanding the next
contingency without resulting in cascading failures.
931. In response to Northern Indiana, our intent is not to mandate
an increase in security from N-1 to N-2, but rather is to ensure there
is no reliability gap in the IROL-related Reliability Standards. To do
this, the Commission believes it is necessary to provide operators with
control actions needed to mitigate an IROL violation while within the
30-minute period after a first contingency. We are not requiring an
increase to N-2, which would require planning the system for any two
contingencies at all times.
932. With respect to California PUC's comment, we note that it is
just as important for day-ahead operation planners to review and derive
system operating limits to deal with a myriad of contingencies for
different system configurations and generation dispatches, as it is for
them to assess the feasibility of returning the system to a secure
operating state after these contingencies have occurred. Similar to
reviewing and deriving SOLs and IROLs to ascertain that system
reliability will be maintained based on the most onerous forecast
conditions and critical contingencies, identifying corrective control
actions would not encompass each and every contingency and system
condition. This is because previous operating experiences and
established operating practices would have covered a significant
portion of the contingencies and the corresponding control actions
already.
933. We further note that for those few IROL contingencies under
the forecast and most onerous system conditions, if operation planners
equipped with a suite of off-line analytical tools, but without any
burden, distraction or interference from real-time operations, cannot
identify the effective control actions, it can be argued that it would
be unrealistic to expect system operators to do so with an additional
requirement--i.e. identification and implementation of an effective
control action all within 30 minutes. In addition, the control actions
identified in the next-day analysis may quite often provide relevant
information to the system operators of the control options they have
available.
934. We believe that our use of NERC's definition of bulk electric
system in combination with its registration process should assuage
California Cogeneration's concerns.
935. In response to APPA's concern that NERC did not provide a
Measure for each Requirement, we reiterate that it is in the ERO's
discretion whether each Requirement requires a corresponding Measure.
The ERO should consider this issue through the Reliability Standards
development process.
936. Accordingly, we approve Reliability Standard IRO-004-1 as
mandatory and enforceable. Further, we direct the ERO to modify IRO-
004-1 through the Reliability Standards development process to require
the next-day analysis to identify control actions that can be
implemented and effective within 30 minutes after a contingency. The
Commission also directs the ERO to consider adding Measures and Levels
of Non-Compliance to the Reliability Standard as requested by APPA.
e. Reliability Coordination--Current Day Operations (IRO-005-1)
937. IRO-005-1 ensures energy balance and transmission reliability
for the current day by identifying tasks that reliability coordinators
must perform throughout the day.
938. In the NOPR, the Commission proposed 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 proposed to direct NERC to submit a modification to IRO-
005-1 that includes Measures and Levels of Non-Compliance. The
Commission proposed 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, the
Commission proposed to direct the ERO to conduct a survey on IROL
practices and actual operating experiences, and indicated that it may
propose further modifications to IRO-005-1 based on the survey
results.\301\
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\301\ NOPR at P 545 (``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 reliability coordinators to
report any violations of IROLs, their causes, the date and time of
the violations, and the duration in which actual operations exceeded
IROL to the ERO on a monthly basis for one year beginning two months
after the effective date of the Final Rule.'')
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[[Page 16508]]
i. Comments
939. FirstEnergy supports the approval of the proposed Reliability
Standard as mandatory and enforceable as interpreted by NERC (i.e.,
that exceeding IROL for less than 30 minutes is not a violation),
pending further action through the NERC Reliability Standards
development process.
940. MidAmerican supports the Commission's proposed survey and
notes that based on its experience, IROL violations have been
faithfully reported across NERC.
941. The CAISO urges the Commission to proceed with caution if
headed in the direction of absolute compliance with IROL. However, it
supports the survey to determine the extent to which systems are
actually ``drifting'' in and out of IROL limits.
942. APPA indicates its support of the Commission's directive to
undertake a survey regarding IROL practices and experiences. However it
feels that it should be NERC's role to decide on the survey. It
contends that, based on the survey results and using the Reliability
Standard development process, NERC would decide what modifications to
IRO-005-2 are appropriate.
943. Entergy agrees that it is appropriate to use a mitigation plan
to resolve an SOL or IROL violation when the actual contingency that
causes an SOL or IROL violation is experienced. However, with an
acceptable mitigation plan, it is not necessary to require transmission
operators to keep facility loading below a level where a potential SOL
or IROL violation would occur assuming a low probability of the
contingency. Entergy requests clarification that the Commission's
guidance is not intended to preclude the use of such alternative
procedures. The Commission should be cautious not to restrictively
define SOL or IROL in a manner that causes the system operator to take
preemptive action through this Reliability Standard to address events
that may technically be SOL or IROL violations, but which have a low
probability of occurrence and can be mitigated through other proven
procedures.
944. ISO-NE agrees that NERC should promptly address the
ambiguities in the current definition of an IROL. It has a concern that
the phrase ``The Transmission Service Provider shall respect these SOLs
and IROLs'' in Requirement R14 may cause confusion that this entity is
expected to respect SOLs and IROLs in the operating time frame.\302\
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\302\ IRO-005-1 Requirement R14 states ``Each Reliability
Coordinator shall make known to Transmission Service Providers
within its Reliability Coordinator Area, SOLs or IROLs within its
wide-area view. The Transmission Service Provider shall respect
these SOLs or IROLs in accordance with filed tariffs and regional
Total Transfer Calculation and Available Transfer Calculation
processes.''
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945. TAPS raises an issue with Requirement R13 that states in part
``[i]n instances where there is a difference in derived limits,* * *
Load-Serving Entities * * * shall always operate the Bulk Electric
System to the most limiting parameter.'' TAPS further states that,
since LSEs do not operate the system within SOLs or IROLs, the only
thing such entities, particularly small ones, can do is shed load. It
contends that if the Reliability Standard is mandatory, it should apply
only within the parameters proposed by NERC--subject to its Bulk
Electric System definition and its June registry criteria. Further,
given the apparent error in the Reliability Standard, the Commission
should ask NERC to re-examine it.
ii. Commission Determination
946. The Commission approves proposed Reliability Standard IRO-005-
1 as mandatory and enforceable. In addition, the Commission directs the
ERO to develop modifications to the Reliability Standard through the
Reliability Standards development process, as discussed below.
947. The Commission clarifies the intent of and need for the
proposed survey. We reiterate that the intent is to learn about the
operating experiences and practices of operating entities;
specifically, how they operate their systems to respect IROLs in the
normal system conditions, i.e. prior to a contingency. The survey
results will facilitate future development and modifications of IROL-
related Reliability Standards to better clarify and eliminate potential
multiple interpretations of respecting IROLs that may exist in the
proposed Reliability Standards.\303\ In addition, the survey will
identify the reliability risks and the frequency and number of
operating practices involving drifting in and out of IROL.\304\ The
survey results will also provide guidance on the frequency, duration
and magnitude of IROL violations, their causes and whether these IROL
violations occur during normal or contingency conditions.
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\303\ NOPR at P 540: IRO-005-1 could be interpreted as allowing
a system operator 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.
\304\ The term ``drifting in and out of IROLs'' refers to
operating the normal system (i.e. prior to a contingency) with
frequent occurrences in which IROLs are exceeded, but each
occurrence lasting less than 30 minutes. Currently, this mode of
operation is not considered as a violation of NERC Reliability
Standards.
---------------------------------------------------------------------------
948. We note the support from FirstEnergy, MidAmerican, CAISO and
APPA for our proposed survey. Regarding MidAmerican's comment that
reporting on IROL violations is a routine practice, we note that the
proposed Reliability Standards only require reporting on those
violations that have exceeded IROLs for longer than 30 minutes. The
current reporting requirements and results will not provide an adequate
assessment of the existing operating practices regarding IROLs and the
reliability risks and the extent of drifting in and out of IROLs.
949. In response to Entergy, the Commission believes that operating
the system within IROL under normal system condition and 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,
may be appropriate. This mode of operation will minimize the system
risk of being one contingency away from potential cascading failures.
950. ISO-NE asks that the ERO should promptly clarify the current
definition for IROL violations. However, we do not share ISO-NE's
concern that transmission service providers may be responsible for
respecting SOLs and IROLs in real-time operation. Requirement R14 only
requires a transmission service provider to use the SOLs and IROLs
provided by the reliability coordinator in its tariff, it does not
require any action in the operating time frame.
951. We do not share TAPS' concern regarding LSEs initiating load
shedding as their own control action to respect IROLs or SOLs. The
appropriate control actions to respect IROLs and SOLs are the
responsibilities of a reliability coordinator and transmission
operator. If load shedding is required, it is the responsibility of a
reliability coordinator or a transmission operator to direct the
appropriate entities including LSEs to carry it out. However, we urge
the ERO to provide further clarification in this regard and include
TAPS' concern in developing the modification of this Reliability
Standard.
952. Accordingly, the Commission approves Reliability Standard IRO-
005-1 as mandatory and enforceable.
[[Page 16509]]
Further, because IRO-005-1 has no Measures or Levels of Non-Compliance,
pursuant to section 215(d)(5) of the FPA and Sec. 39.5(f) of our
regulations, the Commission directs the ERO to develop a modification
to IRO-005-1 through the Reliability Standards development process that
includes Measures and Levels of Non-Compliance. The Commission further
directs that the Measures and Levels of Non-Compliance specific to IROL
violations must be commensurate with the magnitude, duration, frequency
and causes of the violations and whether these occur during normal or
contingency conditions. Finally, the Commission directs the ERO to
conduct a survey on IROL practices and actual operating experiences by
requiring reliability coordinators to report any violations of IROL,
their causes, the date and time, the durations and magnitudes in which
actual operations exceeds IROLs to the ERO on a monthly basis for one
year beginning two months after the effective date of the Final Rule.
We may propose further modifications to IRO-005-1 based on the survey
results.
f. Reliability Coordination--Transmission Loading Relief (IRO-006-3)
953. 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.\305\ 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.
It also includes by reference the equivalent Interconnection-wide
congestion management methods used in the WECC and ERCOT regions.
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\305\ 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.
---------------------------------------------------------------------------
954. In the NOPR, the Commission proposed 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 proposed to direct NERC to submit a modification to IRO-
006-3 that: (1) Includes a clear warning that a 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. In
addition, the Commission proposed to approve the WECC and ERCOT load
relief procedures as superior to the national standard.
i. Comments
955. APPA agrees that IRO-006-3 is sufficient for approval as a
mandatory Reliability Standard. It suggests that the ERO should
consider development of detailed Measures and Levels of Non-Compliance
that address each Requirement in IRO-006-3. Until then, penalties
should not be imposed except for egregious violations and the
associated penalties should be imposed by the Commission.
956. APPA, Entergy and MidAmerican agree that the TLR procedure is
an inappropriate and ineffective tool to mitigate actual IROL
violations and that a clear warning to that effect should be included.
MidAmerican specifically suggests that the warning must also apply to
actual emergency situations in addition to actual IROL violations.
957. Similarly, ISO-NE supports the Commission's conclusions with
regard to reliance on TLRs to address actual IROL violations. Further,
it supports the Commission's proposal that the ERO should modify the
Reliability Standard to provide flexibility for ISOs and RTOs to rely
on redispatch as a means to mitigate an IROL violation.
958. Xcel suggests that instead of the proposed modification of a
clear warning, it should include a requirement that TLR procedures
should not be used for alleviating actual IROL violations. It asserts
that the latter approach would be more measurable than the Commission's
proposed modification.
959. Entergy and MidAmerican believe that TLR procedures can be an
effective mechanism to avoid potential SOL and IROL violations or
potential emergency situations.
960. In contrast, Progress Energy disagrees with the Commission's
reasoning on the ineffectiveness of using TLR procedures to alleviate
actual IROL violations.
ii. Commission Determination
961. The Commission approves IRO-006-3 as mandatory and
enforceable. In addition, we direct the ERO to develop modifications to
the Reliability Standard as discussed below.
962. The Commission remains convinced, based on Blackout
Recommendation No. 31,\306\ the submissions from APPA, Entergy,
MidAmerican, ISO-NE and Xcel, and NERC's comments on the Staff
Preliminary Assessment,\307\ that proposed directives to include a
clear warning that a TLR procedure is an inappropriate and ineffective
tool to mitigate IROL violations and to identify the available
alternatives to use of the TLR procedure to mitigate an IROL violation
are the appropriate improvements to address the deficiencies in using
TLR procedures to mitigate actual IROL violations or actual emergency
situations. The Commission endorses Blackout Recommendation No. 31.
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\306\ Blackout Recommendation No. 31, at 163 is to ``Clarify
that the transmission loading relief (TLR) process should not be
used in situations involving an actual violation of an Operating
Security Limit.''
\307\ The NERC comments to Staff Assessment at 49 state that
``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.''
---------------------------------------------------------------------------
963. The Commission agrees with Entergy and MidAmerican that TLR
procedures can be an effective mechanism to avoid potential IROL
violations and potential emergencies. Regarding this, we reiterate that
our concerns have always been on the use of TLR to mitigate actual
IROLs or actual emergencies, and not on potential IROLs or emergencies,
as indicated in the Blackout Report, Staff Assessment and the NOPR.
964. We do not understand Progress Energy's disagreement because no
reason is provided.
965. Accordingly, in addition to approving the Reliability
Standard, the Commission directs the ERO to develop a modification to
IRO-006-3 through the Reliability Standards development process that
(1) includes a clear warning that the TLR procedure is an inappropriate
and ineffective tool to mitigate actual IROL violations and (2)
identifies in a Requirement the available alternatives to mitigate an
IROL violation other than use of the TLR procedure. In developing the
required modification, the ERO should consider the suggestions of
MidAmerican and Xcel. In addition, the Commission approves the WECC and
ERCOT load relief procedures as superior to the national Reliability
Standard. As identified in the NOPR, the Commission directs the ERO to
modify the WECC and ERCOT procedures to ensure
[[Page 16510]]
consistency with the standard form of the Reliability Standards
including Requirements, Measures and Levels of Non-Compliance.\308\
---------------------------------------------------------------------------
\308\ See NOPR at P 564-65.
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g. Regional Difference to IRO-006-3: PJM/MISO/SPP Enhanced Congestion
Management (Curtailment/Reload/Reallocation)
i. Background
966. As explained in the NOPR, IRO-006-003 provides for a regional
difference for MISO, PJM and SPP.\309\ According to NERC, the 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.
---------------------------------------------------------------------------
\309\ NOPR at P 568.
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967. The regional difference to IRO-006-3 applies the congestion
management process included in Joint Operating Agreements filed by
MISO, PJM and SPP and specified in seams agreements reached among MISO,
PJM, and their neighboring non-market areas during the RTOs' market
formation and expansions. Under the congestion management process in
the waiver, each RTO calculates an amount of energy (market flow)
flowing across coordinated flowgates. These market flows are separated
into their appropriate priorities based on the RTO's schedules and
reservations and are available for curtailment under the appropriate
TLR Levels in the NERC interchange distribution calculator. Under the
TLR method for curtailing interchange transactions and in the per
generator method for generation-to-load impacts, NERC uses a five
percent curtailment threshold, but in the waiver, the RTO's market
flows with an impact of greater than zero percent on a coordinated
flowgate are represented and made available for curtailment under the
appropriate TLR priorities.
968. In their comments on the Staff Preliminary Assessment, MISO-
PJM contended that there is unduly discriminatory treatment of the
market flows of MISO and PJM versus the generation-to-load impacts of
non-market entities because the waiver subjects the RTOs to curtailment
(and the corresponding redispatch costs) in circumstances where the
non-market entities would not be subject to curtailment.
969. In the NOPR, the Commission did not propose to approve or
remand this regional difference.
ii. Comments
(a) Application of the Regional Difference
970. MISO-PJM contends that there is unduly discriminatory
treatment against market flows of MISO and PJM during the application
of the TLR Standard. The RTOs argue that NERC should modify IRO-006-3
and the MISO and PJM regional difference to require modifying the
market flow threshold used by the interchange distribution calculator
to assign relief obligations to MISO, PJM, and SPP from zero to a
standard percentage that is technically feasible to implement on a non-
discriminatory basis, netting of market flow impacts, tag impacts, and
generation-to-load impacts, and reporting to the interchange
distribution calculator all net generation-to-load impacts for both
market and non-market transmission providers. Constellation supports
MISO-PJM's argument that there is unduly discriminatory treatment of
the MISO and PJM market flows compared to the generation-to-load
impacts of non-market entities in the application of the TLR standard.
971. MISO-PJM indicates that they have raised the equity issue with
the NERC Operating Reliability Subcommittee (Operating Subcommittee),
that their markets currently are being asked to curtail market flow
impacts down to zero percent while tagged transactions and generation-
to-load impacts during TLR 5 are being asked to curtail impacts that
are five percent or greater. MISO-PJM states that the NERC Operating
Subcommittee has indicated that they will address reliability issues
only and that they are not the appropriate group to address equity
issues.
(b) Seams Agreements
972. Several entities argue that the Commission should not overturn
the existing IRO-006-3 regional difference. MidAmerican states that
MISO and PJM should continue to pursue a negotiated solution to the
issues outlined in MISO-PJM's filings. Mid-Continent states that the
Commission should reject the MISO-PJM proposal to require NERC to allow
them to report only the transactions with five percent or greater
impacts on flowgates rather than report all transactions for
curtailments, since MISO and PJM offered to report all transactions to
avoid negative impacts on the reliability of the transmission system.
Mid-Continent argues that not doing so would impact the reliability of
the transmission system.
973. Mid-Continent asks the Commission to not implement MISO and
PJM's proposal to modify NERC's procedures and to not override seams
agreements. MidAmerican claims that MISO-PJM comments amount to an
abrogation of existing seams agreements. MidAmerican states that the
seams agreements were negotiated in a give-and-take process between the
parties resulting in the existing waiver which was proposed by PJM and
MISO in response to Commission orders. MidAmerican states that if any
changes are sought to these waivers, they should be addressed in
negotiation with the appropriate parties. MidAmerican suggests that any
changes should be requested by way of the NERC process for developing
Reliability Standards and that any negotiated agreements should be
presented to the Commission for approval. Mid-Continent claims that
MISO-PJM have not provided valid reasons to replace the current
Reliability Standards or to take actions that would modify existing
seams agreements signed by MISO and PJM. Mid-Continent asks the
Commission not to short-circuit the NERC Reliability Standards process
which will give full consideration to the reliability implications of
MISO's and PJM's proposal.
974. APPA agrees with the Commission's proposed approach in
allowing MISO, PJM, NERC and other ``relevant entities'' to continue
their negotiations regarding this regional difference. APPA cautions
that any agreement reached by NERC and approved by the Commission
regarding a regional difference for this Reliability Standard should be
governed by reliability considerations and should not permit market
design considerations to override NERC's Reliability Standards.
MidAmerican suggests a process where the RTOs invite parties to
reconsider the seams agreements, the parties negotiate changes, the
Commission approves new agreements and waivers are then sought from
NERC to the extent necessary. MidAmerican argues that since the RTOs do
not allege any reliability problem there is no need to reject or upend
the existing NERC waiver.
(c) Modifying the Congestion Management Process and Alternatives for
Temporary Application of the Waiver
975. Mid-Continent states that it agrees with the Commission's
proposal to not adopt MISO and PJM's request to instruct NERC to modify
the current waiver to the TLR in the RTOs and believes that instead the
Commission should direct NERC to address these issues through the
Reliability Standards
[[Page 16511]]
development process with input from neighboring systems. Mid-Continent
states that changes to the waiver must not discriminate against non-
market regions; must not negatively impact the reliability of
neighboring systems and must be consistent with seams agreements signed
by the RTOs.
976. NRECA claims that issues associated with market flows and
generation-to-load impacts have not been resolved and is concerned that
MISO-PJM's suggestion that ``consensus'' has been reached on the issues
is premature. NRECA is also concerned that implementation of the MISO
and PJM proposal could increase reliance on TLRs. NRECA urges the
Commission to not short circuit or circumvent the Reliability Standards
development process or the RTO stakeholders process and states that the
Commission should permit the stakeholders to reach full consensus.
977. MISO-PJM indicates that they have been working with both the
NERC Operating Subcommittee and the Congestion Management Process
Working Group (Congestion Working Group) to achieve a consensus on
these changes, and that based on this, the Commission stated in the
NOPR that it prefers that MISO, PJM and others continue negotiations to
resolve these issues rather than imposing a solution on market
participants. MISO-PJM state that they have held extensive discussions
with a group composed of NERC Operating Subcommittee and Congestion
Working Group participants. MISO-PJM indicates that detailed analyses
has been performed to evaluate the effect of changing the market flow
threshold from zero percent to five percent in one percent increments
and that the NERC Operating Subcommittee has recommended that the
market flow threshold used by the interchange distribution calculator
to assign relief obligations to the MISO, PJM, and SPP be changed from
zero percent to three percent for a 12 month interim period. MISO-PJM
assert that at the end of the 12 months, a decision will be made
whether to recommend a permanent change to the market flow threshold
from zero percent to three percent or a change to some other value.
MISO-PJM state that according to the NERC Operating Subcommittee, this
recommendation is to only address the reliability issue raised by MISO,
PJM and SPP so that they are able to meet their relief assignment
during TLR.
978. MISO-PJM also states that to receive congestion management
process Council endorsement and support for the change being developed
by the NERC Operating Subcommittee group, it requires unanimous
approval by the congestion management process Council and that, though
the 12 month field test to change the market flow threshold from zero
percent to three percent has the support of MISO, PJM, SPP and TVA, it
does not have the unanimous approval of all signatories to the seams
agreements. MISO-PJM states that MAPPCOR (MAPP) has not agreed to the
field test recommended by the NERC Operating Subcommittee and that MAPP
has asserted that MISO should continue to honor their contractual
obligation and report market flow impacts down to zero percent for
relief assignments as specified in the MISO-MAPP Seams Operating
Agreement. MISO is concerned that once the field test is complete and
the NERC Operating Subcommittee recommends the use of a three percent
threshold or some other threshold to address the reliability issue, the
MISO may still have a contractual obligation with MAPP to use market
flows down to zero percent for relief assignments. MISO-PJM states that
this contractual obligation can only be altered if MISO and MAPP can
agree on a change to the Seams Operating Agreement but expects
resistance to change the Seams Operating Agreement. MISO and PJM do not
believe they can address the equity issue by continuing discussions
with the NERC Operating Subcommittee.
979. MISO-PJM also state that by continuing to use market flows
down to zero percent for relief assignments on reciprocally coordinated
flowgates between MISO and MAPP, there will be situations where MISO is
unable to meet its relief obligation. MISO-PJM states that they have
sought unsuccessfully to execute redispatch agreements with those
parties who have direct counter-flow on the identified flowgates where
the MISO is unable to meet its relief obligation. MISO-PJM believe that
the Commission should address this continuing discriminatory treatment
of the market impacts on flowgates. MISO-PJM state that of the three
areas where MISO-PJM raised comments on discriminatory treatment of the
markets, only one area (changing the market flow threshold for a 12
month field test) has resulted in steps being taken to address the
discriminatory treatment and that even this one area can only be
considered a partial success because there is only a solution to
address the reliability issue, but not the equity issue.
980. MISO-PJM explain in their supplemental comments that NERC has
demonstrated a willingness to consider the reliability issue by
authorizing a 12 month field test allowing PJM, MISO and SPP market
flows to use a three percent threshold, to observe the impact on
reliability, but will not address what it refers to as ``equity
issues.'' MISO-PJM explains the field test has been approved by all the
reciprocal entities that have signed seams agreements except MAPP.
MISO-PJM state that, at the end of the 12 months, a decision will be
made whether to use a three percent threshold or some other threshold
to address the reliability concerns. MISO-PJM explain that the same
entities that make up the Mid-Continent objected to the field test
because they asserted MISO has a contractual obligation under the MAPP
Seams Operating Agreement to continue reporting its market flows down
to zero percent. MISO-PJM contend that because the MISO has agreed to
honor its contractual obligation during the field test and will
continue to use a zero percent threshold for all flowgates that are
reciprocal between MISO and MAPP, this means that the flowgates under
the control of the Mid-Continent parties will not participate in the
field test and NERC will have no data to show the impact of changing
the market flow threshold to three percent on these flowgates.
981. MISO-PJM state that as long as the regional difference does
not become a mandatory standard during the field test, they are
satisfied that appropriate steps are being taken to address
reliability.
(d) Reporting of Generator to Load Impacts by Non Market Areas
982. MISO-PJM supports modifications to the TLR process that would
require all participants (both market and non-market) to report their
market flow impacts and generator-to-load impacts to the interchange
distribution calculator and honor their allocations when they report
their firm versus their non-firm usage. MISO-PJM believes that taking
this step would also address the threshold equity issue and the netting
issue because all entities would be subject to the same treatment.
MISO-PJM requests that the Commission to either direct NERC to initiate
a process to modify the interchange distribution calculator such that
market flows and generator-to-load impacts from non-market areas are
both reported to the interchange distribution calculator and are
subject to curtailment based on their priorities from the allocations
or that the Commission take action to do so.
983. MISO-PJM states that the reporting of generator-to-load
impacts by the non-market entities is the one area that is not
currently under
[[Page 16512]]
discussion with a stakeholder group. MISO-PJM explains that both the
market and non-market entities receive an allocation on flowgates and
that both the market entities and the non-market entities use the
allocations when selling firm transmission service. MISO-PJM states
that only the market entities report their market flows to the
interchange distribution calculator and use their allocations to
determine what portion of market flows will be considered firm and
believe that the non-market entities could also report their firm and
non-firm generator-to-load usage to the interchange distribution
calculator and receive relief assignments based on this usage. MISO-PJM
indicates that this would remove the assumption that all generator-to-
load impacts from the non-market entities represent firm usage. MISO-
PJM states that reporting relief obligations by one group of
participants and not reporting by the other results in conflicting
actions during the TLR process because market entities suffer the
financial consequences of redispatch at the same time reliability is
not being accomplished due to off-setting actions by non-market
entities.
984. MISO-PJM states that, to address the discriminatory treatment
of the markets, the Commission could order the TLR Reliability Standard
to be modified to have the market entities discontinue reporting their
market flows to the interchange distribution calculator. MISO-PJM
believes that instead of this order, the preference is to have the
market entities continue reporting their market flow impacts and the
non-market entities report their generator-to-load impacts to the
interchange distribution calculator. The allocations would be used to
set the priority of these impacts.
985. Mid-Continent states that the regional difference requiring
PJM and MISO to report all flows instead of net flows was part of the
commitments MISO and PJM made to meet NERC's tagging requirements. Mid-
Continent contends that it is appropriate to treat MISO-PJM market
flows differently because they are greater than the system flows that
resulted from control area-based system operation. Mid-Continent
further claims that MISO cannot achieve the redispatch the interchange
distribution calculator requires because of MISO's own actions since
MISO does not report actual flows to the interchange distribution
calculator and MISO and PJM's congestion management tools do not
utilize all redispatch options.
(e) Accounting for Counter Flows During TLR
986. MISO-PJM state that there have been discussions at the NERC
Operating Subcommittee about taking into account counter-flows during
TLR when assigning relief. MISO-PJM contends that by considering
counter-flows, those entities that are responsible for the loading
problem on a net basis will be responsible for fixing the loading
problem during TLR. MISO-PJM states that the MISO, PJM and SPP markets
operate on a net flow basis and, therefore, have additional reasons for
wanting to consider counter-flows. MISO-PJM expects that by summer
2007, the Task Force will have a recommendation on netting in the
interchange distribution calculator for the NERC Operating Subcommittee
to consider. MISO-PJM state that it is premature to speculate on the
outcome of the discussions with the NERC Operating Subcommittee at this
time. MISO-PJM clarifies that they are not asking the Commission to
take any action on this issue but to let the NERC Operating
Subcommittee address the technical merits of netting impacts in the
interchange distribution calculator.
987. Mid-Continent states that eliminating the requirements to
report flows in both directions may adversely impact reliability
because the interchange distribution calculator will not have enough
information to assign responsibilities to the contributors of a
constraint.
iii. Commission Determination
988. The Commission will not approve or remand this regional
difference. The treatment of the market flows of MISO-PJM versus the
generation-to-load impacts of non-market entities in the application of
the TLR standard has been addressed by the Commission in a number of
cases.\310\ In approving the plans of various transmission owning
utilities to join PJM, the Commission attached several conditions
including a requirement that certain non-market utilities be held
harmless from effects of loop flow and congestion resulting from the
utilities' RTO choices.\311\ Further, during MISO's market start
up,\312\ the Commission determined that the markets could not start
without the MISO having at least a specific, transparent plan for how
it will handle the interface of multiple transmission tariffs and
market-to-non-market seams \313\ and required the MISO to file any
resolution of seams, or a status report of progress on seams resolution
including detailed plans as to how MISO will address seams absent
agreements, within 60 days of the date of the order. The regional
difference to IRO-006-3 applies the congestion management process that
was included in the Joint Operating Agreement filed by MISO, PJM and
SPP and that was specified in the seams agreements reached between
MISO, PJM, and their neighboring non-market areas in order to meet the
Commission's requirements described above.\314\
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\310\ See Alliance Companies, 100 FERC ] 61,137 (2001) and
Midwest Independent Transmission System Operator, Inc. and PJM
Interconnection, L.L.C., 106 FERC ] 61,251 (2004).
\311\ Commonwealth Edison Company and American Electric Power
Service Corporation, 106 FERC ] 61,250 (2004). This order required
ComEd to demonstrate that its proposal held utilities in Wisconsin
and Michigan harmless from all adverse impacts associated with loop
flow or congestion that would result from its choice to join PJM.
\312\ See Midwest Independent Transmission System Operator,
Inc., 108 FERC ] 61,163 (2004).
\313\ To resolve this issue, the Commission encouraged market
participants to use the PJM-Midwest ISO joint operating agreement as
a model or starting point for seams agreements, particularly with
respect to the seams with the various utilities in the MAPP region.
\314\ See Midwest Independent Transmission System Operator,
Inc., 110 FERC ] 61,290 (2005).
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989. The Commission recognizes MISO-PJM's concerns that: (1) The
congestion management process could be placing an undue burden on the
RTO regions to provide redispatch especially on remote flowgates where
an RTO's dispatch has a small impact and (2) under the congestion
management process, the calculation of market flows for relief
assignments on Reciprocal Coordinated Flowgates between the MISO and
MAPP could create situations where MISO is unable to meet its relief
obligation without curtailing load. We also understand that these
concerns are exacerbated by the possibility of civil penalties for non-
compliance with the requirement to use market flows down to zero
percent for relief assignments on reciprocal coordinated flowgates
between MISO and MAPPCOR. Especially during transitions when markets
with multiple control areas are started up, markets are expanded to
include other control areas, or non-market control areas are
consolidated, this can have an effect on the loop flows experienced by
neighboring regions and the redispatch required by the neighboring
regions due to fewer tagged transactions reported to the interchange
distribution calculator. The Commission recognizes that there are
concerns by neighboring entities to be held harmless from increased
redispatch responsibility caused by these transitions.
[[Page 16513]]
990. The Commission concludes that the issues described by MISO-PJM
(i.e., defining the obligation of a certain region to provide
redispatch when a flowgate becomes congested) are best handled through
seams agreements rather than being subject to the NERC processes. We
recognize that the two areas of seams agreements and Reliability
Standards could overlap if the agreements reached do not allow for
reliable outcomes where parties can achieve the relief assigned. As
such, the Commission will neither approve nor remand the waiver of the
regional difference to IRO-006-3 while the 12-month field test allowing
PJM, MISO and SPP market flows to use a three percent threshold is
being conducted. After the 12-month field test is complete, the
Commission will reexamine approving the waiver as a mandatory and
enforceable Reliability Standard.
991. The Commission instructs the RTOs to continue working with the
non-market regions to develop revised seams agreements that allow for
equitable and feasible treatment of market flows in the NERC TLR/
redispatch process. The solution should not harm system reliability and
should not subject either non-RTO transmission owners or the RTO
markets to unreasonable redispatch responsibilities. We note that if
consensus cannot be reached, the RTOs may file a section 205 or section
206 proposal to revise the terms and conditions of the congestion
management process if the terms agreed on in the seams agreements and
Joint Operating Agreement have become unjust or unreasonable or may
file to terminate the agreements as allowed in the seams agreements.
992. The Commission will not adopt MISO-PJM's proposal to require
non-market entities to report their generator-to-load impacts to the
interchange distribution calculator with the allocations used to set
the priority of these impacts in this Reliability Standards process. If
NERC determines that this information and corresponding curtailment
options are needed for reliability, NERC should file to modify IRO-006-
3 to include these additions. However, the economic implications of the
reporting of generator-to-load impacts by non-market entities are not
in the scope of the reliability process and are better addressed on a
case-by-case basis or, as appropriate, in the proceeding on RTO Border
Utility Issues.\315\
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\315\ See RTO Border Utility Issues, Notice of Technical
Conference on Seams Issues for RTOs and ISOs in the Eastern
Interconnections (Docket No. AD06-9-000) (issued Jan. 25, 2007).
---------------------------------------------------------------------------
993. In addressing MISO-PJM's claim that the ERO should modify IRO-
006-3 and the MISO-PJM regional difference to require netting
generation-to-load impacts to recognize counterflow, we will let the
ERO Operating Subcommittee address the technical merits of netting flow
impacts in the interchange distribution calculator.
h. Procedures, Processes, or Plans To Support Coordination Between
Reliability Coordinators (IRO-014-1)
994. The stated purpose of IRO-014-1 is to ensure that each
reliability coordinator's operations are coordinated so 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 exchange of operating
information and coordination of operating plans.
995. In the NOPR, the Commission proposed to approve IRO-014-1 as
mandatory and enforceable.
i. Comments
996. APPA agrees with the Commission's proposed approval of IRO-
014-1 as mandatory and enforceable.
ii. Commission Determination
997. For the reasons stated in the NOPR, the Commission approves
IRO-014-1 as mandatory and enforceable.
i. Notifications and Information Exchange Between Reliability
Coordinators (IRO-015-1)
998. 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.
999. In the NOPR, the Commission proposed to approve IRO-015-1 as
mandatory and enforceable.
i. Comments
1000. APPA agrees with the Commission's proposed approval of IRO-
015-1 as mandatory and enforceable.
ii. Commission Determination
1001. For the reasons stated in the NOPR, the Commission approves
IRO-015-1 as mandatory and enforceable.
j. Coordination of Real-Time Activities Between Reliability
Coordinators (IRO-016-1)
1002. 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.
1003. In the NOPR, the Commission proposed to approve IRO-016-1 as
mandatory and enforceable.
i. Comments
1004. APPA agrees with the Commission's proposed approval of IRO-
015-1 as mandatory and enforceable. However, it indicates that it is
unclear in Level of Non-Compliance 2.1, how a reliability coordinator
can demonstrate that it coordinated with other reliability coordinators
without having retained evidence such as detailed logs or telephone
recordings of having done so.\316\
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\316\ IRO-016-1 Level of Non-Compliance 2.1 states: ``For
potential, actual or expected events which required Reliability
Coordinator-to-Reliability Coordinator coordination, the Reliability
Coordinator did coordinate, but did not have evidence that it
coordinated with other Reliability Coordinators.''
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ii. Commission Determination
1005. For the reasons stated in the NOPR, the Commission approves
IRO-016-1 as mandatory and enforceable.
1006. We construe Level of Non-Compliance 2.1 as requiring evidence
of coordination, but allowing flexibility on the type of evidence.
8. MOD: Modeling, Data, and Analysis
1007. The Modeling, Data and Analysis group of Reliability
Standards is intended to standardize methodologies and system data
needed for traditional transmission system operation and expansion
planning, reliability assessment and the calculation of available
transfer capability (ATC) in an open access environment. The 23 MOD
Reliability 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.\317\ The second category covers steady-state and dynamics
data and models.\318\ The third category
[[Page 16514]]
covers actual and forecast demand data.\319\ The fourth category covers
verification of generator real and reactive power capability.\320\
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\317\ MOD-001-0 through MOD-009-0.
\318\ MOD-010-0 through MOD-015-0.
\319\ MOD-016-0 through MOD-021-0.
\320\ MOD-024-1 through MOD-025-1.
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1008. In the NOPR, the Commission proposed that one out of 23 MOD
Reliability Standards be approved unconditionally, nine be approved
with direction for modification and 13 remain pending with direction
for modification.\321\ The Commission, describing these 13 pending
standards as fill-in-the-blank Reliability Standards, generally
proposed to seek additional information before acting on them.
Responding to CenterPoint's proposal to exempt ERCOT from the MOD
Reliability Standards that address available transfer capability, the
Commission explained that it would consider any regional difference at
the time NERC submits one for Commission review. Therefore, the
Commission stated that if ERCOT wished to request a regional
difference, it should do so through the ERO process.
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\321\ Approved: MOD-018-0; approved with modification: MOD-06-0,
MOD-007-0, MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, MOD-019-0
through MOD-021-0; and pending: MOD-001-0 through MOD-005-0, MOD-08-
0, MOD-09-0, MOD-011-0, MOD-013-1 through MOD-015-0, MOD-024-1 and
MOD-025-1.
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i. Comments
1009. ISO/RTO Council and ISO-NE agree with the Commission's
proposal to neither approve nor remand the 13 MOD Reliability Standards
until NERC supplies additional information. ISO/RTO Council and ISO-NE
also recommend that the Commission go further and defer its approval of
the MOD Reliability Standards that incorporate references to the 13
fill-in-the-blank Reliability Standards until those 13 are approved
unconditionally. ISO/RTO Council and ISO-NE believe that the following
Reliability Standards are dependent upon the 13 fill-in-the-blank
standards: MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, MOD-018-0, MOD-
019-0, and MOD-021-0 and as such, the Commission should not approve and
make them enforceable at this time. ISO-NE warns that these listed
standards share the same infirmities as the 13 the Commission found it
could not yet approve. ISO-NE cautions that until the missing
information is provided in the 13 cross-referenced standards, it will
be impossible for the affected entities to determine what criteria they
are expected to satisfy.
1010. EPSA, in contrast to ISO/RTO Council and ISO-NE, expresses
its concern with the Commission's proposal not to act on the 13 fill-
in-the-blank standards. EPSA considers the fill-in-the-blank standards
vitally important to reliability and competitive markets and worries
that progress may be lost while the regions endeavor to file the
additional required information.
ii. Commission Determination
1011. The Commission will adopt the NOPR proposal and retain the
same disposition of the MOD Reliability Standards that it proposed
there. We confirm in this Final Rule that one out of 23 MOD standards
is approved unconditionally, nine are approved with direction for
modification and 13 remain pending with direction for modification. We
will discuss our rationale for this decision in the Commission
Determination section for each particular Reliability Standard.
1012. We reject ISO/RTO Council and ISO-NE's request that we defer
our approval of Reliability Standards from the MOD group that
incorporate references to the 13 fill-in-the-blank standards. While we
understand ISO/RTO Council and ISO-NE's concern about cross-referencing
pending Reliability Standards, the data that is needed will be provided
as described in the Common Issues section.\322\ In the interim,
compliance with the pending Reliability Standards should continue on a
voluntary basis, and the Commission considers compliance with them a
matter of good utility practice. The Commission believes, moreover,
that the blanks will be filled in in a timely manner, since in this
rule we require the ERO to develop a Work Plan and submit a compliance
filing describing the process for collection of the information set
forth in the deferred standards.
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\322\ See Common Issues Pertaining to Reliability Standards:
Fill-in-the-Blank Standards, supra section II.E.5.
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1013. In response to EPSA's concern that opportunities for
discrimination and concerns about reliability remain while we await
additional information, we emphasize that the Commission has provided
specific direction regarding appropriate modifications to the MOD
standards here and in Order No. 890, and has required the submission of
a Work Plan for completion of that work within 90 days.\323\ Moreover,
the OATT and OASIS transparency reforms adopted in Order No. 890 will
ensure that opportunities for discrimination will be minimized while
NERC completes work on the MOD Reliability Standards.
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\323\ OATT Reform Final Rule, Order No. 890, issued February 15,
2007.
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b. MOD Standards Related to ATC, TTC, CBM and TRM
i. OATT Reform and the MOD Standards
1014. As pointed out in the NOPR, the Commission has been
considering ATC, TTC, CBM and TRM calculation issues in Docket Nos.
RM05-17-000 and RM05-25-000, and addressed them in Order No. 890. In
order to maintain a consistent approach with regard to ATC issues, we
confirm here the determinations made in Order No. 890. Each such
determination is addressed below.
1015. In Order No. 890, the Commission addressed the potential for
undue discrimination by requiring industry-wide consistency and
transparency of all components of ATC calculation methodology and
certain definitions, data and modeling assumptions. The Commission also
indicated there that the lack of consistent, industry-wide ATC
calculation standards poses a threat to the reliable operation of the
Bulk-Power System, particularly with respect to the inability of one
transmission provider to know with certainty its neighbors' system
conditions affecting its own ATC values. As a result of this
reliability component, the Commission asserted that the proposed ATC
reforms are also supported by FPA section 215, through which the
Commission has the authority to direct the ERO to submit a Reliability
Standard that the Commission considers appropriate to implement FPA
section 215.\324\
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\324\ FPA section 215(d)(5).
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1016. In Order No. 890, the Commission directed public utilities,
working through NERC and NAESB, to develop Reliability Standards and
business practices to improve the consistency and transparency of ATC
calculations. The Commission required public utilities, working through
NERC, to modify the ATC-related Reliability Standards within 270 days
of publication of Order No. 890 in the Federal Register. The Commission
also directed public utilities to work through NAESB to develop
business practices that complement NERC's new Reliability Standards
within 360 days of publication of Order No. 890 in the Federal
Register. Finally, the Commission directed NERC and NAESB to file a
joint status report on standards and business practices development,
and a Work Plan for completion of this
[[Continued on page 16515]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 16515-16564]] Mandatory Reliability Standards for the Bulk-Power System
[[Continued from page 16514]]
[[Page 16515]]
task, within 90 days of publication of Order No. 890 in the Federal
Register.
1017. The electric utility industry has 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 Task Force to review NERC's standards on
ATC, which issued a final report in 2005.\325\ Based on the
recommendations in the NERC Report, NERC has begun two Standards
Authorization Request proceedings to revise the standards on ATC.\326\
NAESB has also begun a proceeding to develop business practice
standards to enhance the processing of transmission service requests
that affect ATC calculation. Following the issuance of the OATT Reform
NOPR on May 19, 2006, and the Reliability Standards NOPR on October 19,
2006, NERC accelerated development of these standards in accordance
with the guidelines provided in these NOPRs. NERC and NAESB
representatives participated in the Commission's Technical Conference
held on October 12, 2006, and informed the Commission on the status of
Reliability Standards development.\327\ NERC posted the Draft Standard
MOD-001-1, proposing ATC/TTC/AFC (Available Flowgate Capability)
revisions, on its Web site on February 15, 2007.\328\
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\325\ 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: fttp://http://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf
.
\326\ 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.
\327\ Technical Conference regarding Preventing Undue
Discrimination and Preference in Transmission Service under RM05-25
et al. (October 12, 2006).
\328\ That posting preceded by one day the issuance of Order No.
890. Therefore, the posted draft Standard MOD-001-1 does not reflect
the requirements of Order No. 890, but rather is guided by the NOPR
issued in the OATT Reform and Reliability Standards proceedings.
---------------------------------------------------------------------------
(a) Comments
1018. EPSA commends the Commission for recognizing the direct
connection between the MOD group of Reliability Standards and the
initiative to reform Order No. 888 to address existing opportunities to
discriminate against competitive power suppliers in access to the
transmission system. TAPS and EPSA note that in both the OATT Reform
NOPR and the Reliability Standards NOPR, the Commission has articulated
serious concerns about the lack of clarity, transparency and uniformity
in the critical calculations pertaining to one of the most fundamental
aspects of the wholesale bulk power transmission system, and urge the
Commission to make these calculations transparent, consistent, and
better yet, regional. TAPS agrees with Staff's concerns raised in the
NOPR about ATC, TTC, CBM and TRM standards. Constellation particularly
supports the proposed changes to MOD-001-0, MOD-004-0, MOD-006-0 and
MOD-007-0 because these Reliability Standards, as modified, will
provide more information to users regarding ATC, TTC, existing
transmission commitments (ETC), AFC, CBM and TRM, and that information
will begin the process of providing consistent standards for their
calculation.
1019. Constellation agrees with EPSA and cautions that it will take
time for NERC to develop, and for the Commission to definitively
approve, ATC-related standards. Constellation therefore proposes that
the Commission should, upon issuance of a Final Rule, require
transmission providers to post the information that the Commission
directs regarding these values, even if work toward more consistency is
not yet complete. Constellation believes that this will aid in ensuring
that users request and receive more reliable transmission service on a
nondiscriminatory basis.
1020. Contrary to the majority of commenters that support
Commission action regarding ATC issues, MISO states that a Reliability
Standard is not the place to address perceived comparability issues.
MISO states that NERC is responsible for Reliability Standards, but not
for tariffs and business practices that deal with market and equity
issues.
(b) Commission Determination
1021. We agree with the many commenters that recognize the direct
connection between the MOD group of Reliability Standards and available
transfer capability methodologies addressed in Order No. 890, in which
we developed policies to lessen, if not fully eliminate, opportunities
to discriminate against competitive power suppliers in access to the
transmission system.
1022. We recognize the concerns raised by EPSA and Constellation
that opportunities for discrimination and related reliability concerns
may remain during the interim Reliability Standards modification
process, in part because of the discretion that transmission service
providers will retain in calculating ATC values. We point out, however,
that all transmission providers are required to file a modified
Attachment C to their OATTs detailing their ATC calculation
methodologies in advance of the development of the new Reliability
Standards. All transmission providers are required to comply with their
OATTs, and are subject to the filing of a complaint or Commission-
initiated enforcement action if discrimination occurs. Regarding
Constellation's recommendation that the Commission act in advance, and
require transmission service providers to post the information that the
Commission directs regarding ATC values, even if work toward more
consistency is not yet complete, we clarify that we will require
transmission service providers to comply with existing ATC-related
posting obligations on OASIS as supplemented by Order No. 890. These
requirements are not subject to standardization by the ERO, and will be
effective in accordance with the timeline stated in Order No. 890.
1023. We disagree with MISO's contention that the Reliability
Standards are an inappropriate venue for addressing ATC comparability
issues. ATC raises both comparability and reliability issues, and it
would be irresponsible to take action under FPA section 206 to require
consistency in ATC calculations without considering the reliability
impact of those decisions. Therefore, the Commission in Order No. 890
provided direction to public utilities, working through NERC and NAESB,
regarding development of the ATC-related Reliability Standards and
business practices, and we repeat that direction here.
c. Documentation of Total Transfer Capability and Available Transfer
Capability Calculation Methodologies (MOD-001-0)
1024. 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 each
regional reliability organization to develop a regional TTC and ATC
methodology in conjunction with its members and to post the most recent
version of its TTC and ATC methodologies on a Web site accessible by
NERC, the regional reliability organization, and transmission users.
1025. In the NOPR, the Commission identified MOD-001-0 as a fill-
in-the-
[[Page 16516]]
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. The NOPR stated
that the Commission would not propose to approve or remand MOD-001-0
until the ERO submits additional information.
1026. Although the Commission did not propose any action with
regard to MOD-001-0, it addressed a number of concerns regarding the
Reliability Standard, consistent with those proposed in the OATT Reform
NOPR. The Commission proposed that this standard should: (1) At a
minimum, provide a framework for ATC, TTC and ETC calculation; (2)
require disclosure of algorithms and processes used in ATC calculation;
(3) identify a detailed list of information to be exchanged among
transmission providers for the purposes of ATC modeling; (4) include
requirements that the assumptions used in ATC and AFC calculations be
consistent with those used for planning expansion or operation of the
Bulk-Power System to the maximum extent practicable; \329\ (5) include
a requirement that applicable entities make available assumptions and
contingencies underlying ATC and TTC calculations; (6) address only ATC
while the TTC should be addressed under FAC-012-1; and (7) identify to
whom MOD-001-0 standards apply, i.e., users, owners and operators of
the Bulk-Power System.\330\ We will discuss the comments and Commission
conclusions for each of these modifications separately below.
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\329\ NOPR at P 609.
\330\ Id. at P 610. We note that our observation regarding
applicable entities here also applies to MOD-002-0, MOD-003-0, MOD-
004-0, MOD-005-0, MOD-008-0, MOD-009-0, MOD-011-0, MOD-013-0, MOD-
014-0, MOD-015-0, MOD-016-0, MOD-024-0 and MOD-025-0.
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i. Comments
1027. APPA agrees with the Commission that MOD-001-0 in its current
form is a fill-in-the-blank standard, is not sufficient in its current
form and should not be accepted for approval as a mandatory Reliability
Standard until the accompanying regional procedures are submitted and
approved.
ii. Commission Determination
1028. The Commission adopts the NOPR proposal not to approve or
remand MOD-001-0 until the ERO submits additional information.
Consistent with Order No. 890, and comments received in response to the
NOPR, the Commission directs the ERO to consider modifications of MOD-
001-0 through the Reliability Standards development process as
discussed below.
iii. Provide a Framework for ATC, TTC and ETC Calculation
(a) Comments
1029. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to, at a minimum, provide a framework for ATC, TTC and ETC
calculation.
(b) Commission Determination
1030. We continue to believe that MOD-001-0 should, at a minimum,
provide a framework for ATC, TTC and ETC calculations. This framework
should consider industry-wide consistency of all ATC components and
certain data inputs and exchange, modeling assumptions, calculation
frequency, and coordination of data relevant for the calculation of
ATC. Consistent with Order No. 890, we do not require a single
computational process for calculating ATC for several reasons. First,
it is not our intent to require transmission providers to incur the
expense of developing and adopting a new one-size-fits-all software
package to calculate ATC without proven benefits. More importantly, we
find that the potential for discrimination and decline in reliability
level does not lie primarily in the choice of an ATC calculation
methodology, but rather in the consistent application of its
components, and input and exchange data, along with modeling
assumptions. Consistent and transparent ATC calculation will provide
equivalent results between regions and will therefore prevent
transmission service providers from overselling transfer capability
that can stress conditions on their own and adjacent systems, and
jeopardize reliability. In addition, we are especially concerned with
the lack of data exchange between neighboring transmission service
providers, which is a prerequisite for accurate calculation of ATC.
1031. The Commission understands that the ERO currently is
developing three ATC calculation methodologies (contract or rating path
ATC, network ATC, and network AFC).\331\ If all of the ATC components,
and certain data inputs and assumptions are consistent, the three ATC
calculation methodologies will produce predictable and sufficiently
accurate, consistent, equivalent and replicable results. It is
therefore not necessary to require a single industry-wide ATC
calculation methodology.
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\331\ October 12, 2006 Technical Conference regarding Preventing
Undue Discrimination and Preference in Transmission Service under
RM05-25 et al. These three methodologies are different computational
processes to determine a transmission system's ATC. The first,
contract path, examines TTC for every A-to-B path on the system in
concert with all others, reduces ATC by path for ETC, TRM and CBM,
as appropriate, and produces ATC for each path. The second method,
network ATC, uses a simulator to look not at each path, but at each
transmission element (line, substation, etc.) and run first
contingency simulations to establish ATC on a network basis, rather
than a path basis. The third method, network AFC, uses a simulator
to examine critical flowgates over a wider area, then requires a
second step to convert AFC values to particular path ATC values.
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1032. In addition, consistent with Order No. 890, we note that
there is neither a definition of AFC/TFC (Total Flowgate Capability) in
the ERO's glossary nor an existing Reliability Standard that discusses
AFC. Consistent with our approach to achieving consistency and
transparency, we direct the ERO to develop AFC/TFC definitions and
requirements used to identify a particular set of transmission
facilities as flowgates. We extend the same requirements for industry-
wide consistency of all AFC components and certain data inputs and
exchange, modeling assumptions, calculation frequency, and coordination
of data relevant for the calculation of AFC as we stated above for ATC.
However, we remind transmission providers that our regulations require
the posting of ATC values associated with a particular path, not AFC
values associated with a flowgate. Accordingly, transmission providers
using an AFC methodology must convert flowgate (AFC) values into path
(ATC) values for OASIS posting. In order to display consistent posting
of ATC and TTC values on OASIS, we direct the ERO to develop a
Requirement in the Reliability Standard for conversion of AFC into ATC
values for use by transmission providers that currently apply flowgate
methodology.
1033. We underscore Order No. 890's objective of greater
consistency in ETC calculations. The Commission directs the ERO to
develop a consistent approach for determining the amount of transfer
capability a transmission provider may set aside for its native load
and other committed uses. We expect that the ERO will address ETC
through the MOD-001-0 Reliability Standard rather than through a
separate Reliability Standard. By using MOD-001-0, the ETC calculation
principles can be adjusted to apply to each of the three ATC
methodologies being developed by the ERO. In order to provide specific
direction to public utilities and the ERO, we determine that
[[Page 16517]]
ETC should be defined to include committed uses of the transmission
system, including: (1) Native load commitments (including network
service); (2) grandfathered transmission rights; (3) firm and non-firm
point-to-point reservations; (4) rollover rights associated with long-
term firm service and (5) other uses identified through the ERO
process. ETC should not be used to set aside transfer capability for
any type of planning or contingency reserve; these are to be addressed
through CBM and TRM.\332\ In addition, in the short-term ATC
calculation, all reserved but unused transfer capability (non-
scheduled) must be released as non-firm ATC.
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\332\ TRM also includes such things as loop flow and parallel
path flow.
---------------------------------------------------------------------------
1034. We reiterate the finding in Order No. 890 that including all
requests for transmission service in ETC is likely to overstate usage
of the system and understate ATC. Accordingly, we find that
reservations that have the same point of receipt (POR) (generator) but
different point of delivery (POD) (load), for the same time frame,
should not be modeled in the ETC calculation simultaneously if their
combined reserved transmission capacity exceeds the generator's
nameplate capacity at a POR. This will prevent unrealistic use of
transmission capacity associated with power output from a generator
identified as a POR. One approach that could be used is examining
historical patterns of actual reservation use during a particular
season, month, or time of day.
1035. In summary, we direct the ERO to modify MOD-001-0 to provide
a framework for ATC, TTC and ETC calculation that, consistent with the
discussion above: (1) Requires industry-wide consistency of all ATC
components and certain data inputs and exchange, modeling assumptions,
calculation frequency, and coordination of data relevant for the
calculation of ATC; (2) provides predictable and sufficiently accurate,
consistent, equivalent, and replicable ATC calculations regardless of
the methodology used by the region; (3) provides the definition of AFC
and method for its conversion to ATC; (4) lays out clear instructions
on how ETC should be defined and (5) identifies to whom MOD-001-0
Reliability Standards apply, i.e., users, owners and operators of the
Bulk-Power System.
iv. Require Disclosure of Algorithms and Processes Used in ATC
Calculation
(a) Comments
1036. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to require documentation including mathematical algorithms,
process flow diagrams, data inputs and identification of flowgates.
(b) Commission Determination
1037. The Commission adopts the proposal from the NOPR to direct
the ERO to modify Reliability Standard MOD-001-0 to require disclosure
of the algorithms and processes used in ATC calculation. In addition,
consistent with Order No. 890, the Commission believes that further
clarification is necessary regarding the ATC calculation algorithm for
firm and non-firm ATC.\333\ Currently, the ERO has no specifications
for calculating non-firm ATC. We find that the same potential for
discrimination exists for non-firm transmission service as for firm
service, and greater uniformity in both firm and non-firm ATC
calculations will substantially reduce the remaining potential for
undue discrimination. Therefore, we direct the ERO to modify
Reliability Standard MOD-001-0 to require disclosure of the algorithms
and processes used in ATC calculation, and also to implement the
following principles for firm and non-firm ATC calculations: (1) For
firm ATC calculations, the transmission provider shall account only for
firm commitments and (2) for non-firm ATC calculations, the
transmission provider shall account for both firm and non-firm
commitments, postbacks of redirected service, unscheduled service and
counterflows.
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\333\ The NERC ATC definition does not differentiate firm and
non-firm ATC from the following high level generic ATC definition: A
measure of the transfer capability remaining in the physical
transmission network for further commercial activity over and above
already committed uses. It is defined as Total Transfer Capability
less existing transmission commitments (including retail customer
service), less a Capacity Benefit Margin, less a Transmission
Reliability Margin.
---------------------------------------------------------------------------
v. Identify a Detailed List of Information To Be Exchanged Among
Transmission Providers for the Purposes of ATC Modeling
(a) Comments
1038. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to require applicable entities to identify a detailed list of
information to be shared.
(b) Commission Determination
1039. The Commission adopts the NOPR proposal and reiterates the
requirement in Order No. 890 that the ERO must revise the MOD
Reliability Standards to require the exchange of data and coordination
among transmission providers. We direct the ERO to modify MOD-001-0 to
ensure that the following data, at a minimum, 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 recalculation frequency and times and (7) source/
sink modeling identification.\334\ The Commission concludes that the
exchange of such data is necessary to support the reforms requiring
consistency in the determination of ATC adopted in this Final Rule. As
explained above, transmission providers are required to coordinate the
calculation of TTC/TFC and ATC/AFC with others, and this requires a
standard means of exchanging data.
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\334\ NOPR at P 169.
---------------------------------------------------------------------------
vi. Include Requirements That the Assumptions Used in ATC and AFC
Calculations Should Be Consistent, to the Maximum Extent Practicable,
With Those Used for Planning the Expansion or Operation of the Bulk-
Power System
(a) Commission Determination
1040. The Commission adopts the NOPR's proposal to require
transmission providers to use data and modeling assumptions for short-
and long-term ATC calculations that are consistent with those used for
the planning of operations and system expansion, to the maximum extent
practicable. This includes, for example: (1) Load levels; (2)
generation dispatch; (3) transmission and generation facilities
maintenance schedules; (4) contingency outages; (5) topology; (6)
transmission reservations; (7) assumptions regarding transmission and
generation facility additions and retirements and (8) counterflows,
which must be the same in the models used in the transmission
operational and planning studies performed for the transmission
providers' native load. We find that requiring consistency in the data
and modeling assumptions used for ATC calculation will remedy the
potential for undue discrimination by eliminating discretion and
ensuring comparability in the manner in which a
[[Page 16518]]
transmission provider operates and plans its system to serve native
load, and the manner in which it calculates ATC for service to third
parties.
1041. We clarify that we require consistent use of assumptions
underlying operational planning for short-term ATC and expansion
planning for long-term ATC calculation. We also clarify that there must
be a consistent basis for or approach to determining load levels in
each of these sets of calculations. For example, one approach may be
for transmission providers to calculate load levels using an on- and
off-peak model for each month when evaluating yearly service requests
and calculating yearly ATC. The same (peak- and off-peak) or
alternative approaches may be used for monthly, weekly, daily and
hourly ATC calculations. Regardless of the ultimate choice, it is
imperative that all transmission providers use the same approach to
modeling load levels to eliminate undue discrimination and enable the
meaningful exchange of data among transmission providers. Accordingly,
we direct the ERO to develop consistent requirements for modeling load
levels in MOD-001-0.
1042. With respect to modeling of generation dispatch, we direct
the ERO to develop requirements in MOD-001-0 specifying how
transmission providers should determine which generators should be
modeled in service, including guidance on how independent generation
should be considered. Accordingly, we direct the ERO to revise
Reliability Standard MOD-001-0 by specifying that base generation
dispatch will model: (1) All designated network resources and other
resources that are committed to or have the legal obligation to run, as
they are expected to run and (2) all uncommitted resources that are
deliverable within the control area, economically dispatched as
necessary to meet balancing requirements.
1043. Regarding transmission reservations modeling, we direct the
ERO to develop requirements in Reliability Standard MOD-001-0 that
specify: (1) A consistent approach on how to simulate reservations from
points of receipt to points of delivery when sources and sinks are
unknown and (2) how to model existing reservations.
1044. Consistent with Order No. 890, the Commission directs the ERO
to modify Reliability Standard MOD-001-0 to require ATC to be updated
by all transmission providers on a consistent time interval and in a
manner that closely reflects the actual topology of the system, e.g.,
generation and transmission outages, load forecasts, interchange
schedules, transmission reservations, facility ratings and other
necessary data. This process must also consider whether ATC should be
calculated more frequently for constrained facilities.
1045. In conclusion, we direct the ERO to modify MOD-001-0 to
require that: (1) Assumptions used for short-term ATC calculations be
consistent with those used for operation planning to the maximum extent
practicable; (2) assumptions used for long-term ATC calculations be
consistent with those used for system planning to the maximum extent
practicable and (3) ATC be updated by all transmission providers on a
consistent time interval.
vii. Include a Requirement That Applicable Entities Make Available
Assumptions and Contingencies Underlying ATC and TTC Calculations
(a) Comments
1046. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to include a requirement that applicable entities make available
a comprehensive list of assumptions and contingencies underlying ATC
and TTC calculations.
(b) Commission Determination
1047. We adopt the NOPR's proposal that this Reliability Standard
should include a requirement that applicable entities make available a
comprehensive list of assumptions and contingencies underlying ATC/AFC
and TTC/TFC calculations. While we require the submission of
contingency files under MOD-010-0, here we only direct the ERO to
consider development of a requirement that the transmission service
provider declare what type of contingencies it uses for specific
calculations of ATC/AFC and TTC/TFC, and release the contingency files
upon request if not submitted with the data filed with the ERO in
compliance with MOD-010-0.
1048. In order to increase the transparency of ATC calculations, we
adopt the NOPR's proposal and direct the ERO to develop in MOD-001-0 a
requirement that each transmission service provider provide on OASIS
its OATT Attachment C, in which Order No. 890 requires transmission
providers to include a detailed description of the specific
mathematical algorithm the transmission provider uses to calculate both
firm and non-firm ATC for various time frames such as: (1) The
scheduling horizon (same day and real-time), (2) operating horizon (day
ahead and pre-schedule) and (3) planning horizon (beyond the operating
horizon). In addition, a transmission provider must include a process
flow diagram that describes the various steps that it takes in
performing the ATC calculation.
viii. Address Only ATC While TTC Should Be Addressed Under FAC-012-1
(a) Comments
1049. APPA concurs with the NOPR's proposal that TTC should be
standardized under FAC-012-1, and that there appears to be little or no
distinction between the definitions for TTC (MOD-001-0) and TC (FAC-
012-1). APPA anticipates that this distinction will either be clarified
or eliminated through ongoing Reliability Standards development
activity.
1050. Conversely, MidAmerican notes that the transfer capability
covered by FAC-012-1 may not relate to the TTC that is the subject of
the MOD-001-0 standard. MidAmerican opines that the purpose of the FAC-
012-1 standard is to ensure that each reliability coordinator and
planning authority documents the methodology used to develop inter- and
intra-regional transfer capabilities used in the reliable planning and
operation of the Bulk-Electric System. MidAmerican further details that
transfer capabilities that are covered by FAC-012-1 could be used by a
reliability coordinator to operate the system in a temporary situation
or by the planning authority as the basis for a sensitivity case. It
adds that in neither of these cases would these transfer capabilities
necessarily be included in calculations for ATC that would be used for
offering transmission capacity for sale.
(b) Commission Determination
1051. We adopt the NOPR proposal and require that TTC be addressed
under the Reliability Standard that deals with transfer capability such
as FAC-012-1, rather than MOD-001-0. The FAC series of standards
contain the Reliability Standards that form the technical and
procedural basis for calculating transfer capabilities. FAC-008-1
provides the basis for determining the thermal ratings of facilities
while FAC-009-1 provides the basis for communicating those ratings.
FAC-010-1 and FAC-011-1 provide the system operating limits
methodologies for the planning and operational horizon respectively and
FAC-014 provides for the communication of those ratings.\335\
---------------------------------------------------------------------------
\335\ FAC-010, FAC-011, and FAC-014 are addressed in Docket No.
RM07-03 because they were submitted later than the original 107
Reliability Standards and we did not have sufficient time to allow
appropriate review and comment.
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[[Page 16519]]
1052. The Commission directs the ERO, through the Reliability
Standards development process, to modify FAC-012-1 and any other
appropriate Reliability Standards to assure consistency in the
determination of TTC/TFC for services provided under the pro forma
OATT, and requires that those processes be the same as those used in
operation and planning for native load and reliability assessment
studies. Changes to the process of calculating TTC are appropriate if
implementation is coordinated with revisions to the other applicable
operating or planning standards. We acknowledge that reliability
regions have historically calculated transfer capability using
different approaches, and we agree that regional differences should be
respected.\336\ However, as already discussed above regarding ATC, TTC
requirements will be determined in the ERO Reliability Standards
development process, and any request for a regional difference from the
Reliability Standards must take place through the ERO process.
---------------------------------------------------------------------------
\336\ For example, WECC has a documented open process for
establishing TTC for the Western Interconnection.
---------------------------------------------------------------------------
1053. We disagree with MidAmerican's opinion that transfer
capabilities that are addressed by FAC-012-1 are necessarily different
from TTC used for ATC calculation. The NERC glossary defines transfer
capability (TC) \337\ as essentially identical to TTC.\338\ We believe
that modeling principles for simulating power transfers and
determination of transfer capabilities should be the subject of a
single standard. Those principles should be the same regardless of
whether transfer capability is used for the purpose of operations,
planning or offering for sale. By modeling principles we refer to the
way transfers are simulated and the type of analysis that should be
performed, such as steady-state, dynamic stability or voltage
stability. We are certain that consistent calculation of transfer
capabilities will prevent over- and under-estimation of the total
transfer capability available for sale. We agree with APPA that this
distinction should either be clarified or eliminated through the
ongoing Reliability Standards development process, and therefore direct
the ERO to modify MOD-001-0 to address TTC under transfer capability-
related standards such as the FAC group of Reliability Standards.
---------------------------------------------------------------------------
\337\ Transfer Capability is defined in the 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 18.
\338\ 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.'' Id.
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ix. Identify the Entities To Whom the MOD Standards Apply
(a) Comments
1054. APPA agrees in part with the Commission's conclusion that
``NERC should identify the applicable entities in terms of users,
owners and operators of the Bulk-Power Systems.'' \339\ APPA, however,
is concerned that this approach may confuse rather than clarify
compliance responsibilities. According to APPA, a regional organization
in conjunction with entities that plan, own, operate (and use)
transmission facilities within each region must be involved in the
development of any regional TTC and ATC methodology. In this context,
APPA views the ``regional reliability organization'' as the technical
arm of the reliability region, made up of the various committees whose
members are users, owners and operators of the Bulk-Power System, along
with support from the regional reliability organization staff. Further,
APPA notes that ultimately, it is these core users, owners and
operators of the Bulk-Power System that are responsible for the
development of and adherence to the ATC methodology, and that the
regional reliability organization, as an organization, is responsible
for ensuring that the methodology is developed (under R1) and publicly
posted (under R2).
---------------------------------------------------------------------------
\339\ NOPR at P 610.
---------------------------------------------------------------------------
1055. In addition, APPA states that under the statutory framework
established in FPA section 215, as interpreted by the Commission in
Order No. 672, it is clear that the compliance monitor within each
region is the Regional Entity, and the Regional Entity is not a user,
owner or operator of the Bulk-Power System. APPA notes that while
regional delegation agreements may be used to impose certain
reliability compliance functions upon Regional Entities and their
affiliates, no Regional Entity should be charged with enforcing
compliance against itself. Ultimately, APPA is concerned that the
quality of regional modeling and technical assessments will be
diminished if the collaborative efforts used for the past 50 years of
interconnected operations are displaced due to pressures to identify a
single entity or class of entities with direct compliance
responsibilities for regional modeling standards. APPA states that
identifying all users, owners and operators as responsible entities
does not answer the question either. APPA expresses its intention that
it will work with NERC and with other stakeholders to ensure that this
industry-based expertise is maintained and enhanced, while ensuring
that responsible entities are identified in this and other NERC
standards.
(b) Commission Determination
1056. APPA is suggesting that respective regional organizations,
their technical staff, and committees of users, owners and operators of
the Bulk-Power System be charged with developing the methodologies. We
disagree. These Reliability Standards should be developed through the
Commission-approved Reliability Standards development process which
will identify the entities that should implement the Reliability
Standards, the Requirements necessary to achieve the goals identified
in Order No. 890, and the Measures necessary to monitor compliance.
1057. The Commission agrees with APPA that the collaborative
efforts and knowledge developed over decades of interconnected
operation should not be wasted. We do not believe that will happen
through the Reliability Standards development process and that all of
the applicable entities will have significant roles to play in
achieving the goal the Commission has set out in Order No. 890.
Therefore, we adopt the proposal in the NOPR and direct the ERO to
modify MOD-001-0 to reflect the users, owners and operators to which
the Reliability Standard will apply.
x. Summary of Commission Determination
1058. Accordingly, the Commission neither accepts nor remands MOD-
001-0 until the ERO submits additional information. Although the
Commission does not propose any action with regard to MOD-001-0, we
address above a number of concerns regarding the Reliability Standard,
consistent with those set forth in Order No. 890. We direct the ERO to
develop modifications to the Reliability Standard through the
Reliability Standards development process that: (1) Provide a framework
for ATC, TTC and ETC calculation,
[[Page 16520]]
developing industry-wide consistency of all ATC components; (2) require
disclosure of algorithms, for both firm and non-firm ATC and processes
used in the ATC calculation; (3) identify a detailed list of
information to be exchanged among transmission providers for the
purposes of ATC modeling; (4) include a requirement that the
assumptions used in ATC and AFC calculations should be consistent with
those used for planning the expansion or operation of the Bulk-Power
System to the maximum extent practicable; (5) include a requirement
that ATC be updated by all transmission providers on a consistent time
interval; (6) include a requirement that applicable entities make
available assumptions and contingencies underlying ATC and TTC
calculations; (7) address only ATC/AFC while TTC/TFC should be
addressed under transfer capability standards such as FAC-012-1 and (8)
identify the applicable entities in terms of users, owners and
operators of the Bulk-Power System.
d. Review of Transmission Service Provider Total Transfer Capability
and Available Transfer Capability Calculations and Results (MOD-002-0)
1059. 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 and (3) provide the results of its most current
reviews to NERC upon request.
1060. In the NOPR, the Commission identified MOD-002-0 as a fill-
in-the-blank 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. The NOPR stated that the Commission would not propose to
approve or remand MOD-002-0 until the ERO submits additional
information.
i. Comments
1061. APPA agrees that MOD-002-0 is a fill-in-the-blank standard.
It is not sufficient in its current form and should not be approved as
a mandatory Reliability Standard until the accompanying regional
procedures are submitted and approved.
ii. Commission Determination
1062. The Commission adopts the NOPR proposal not to approve or
remand MOD-002-0 until the ERO submits additional information. 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 neither approves nor
remands 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.
e. Regional Procedure for Input on Total Transfer Capability and
Available Transfer Capability Methodologies and Values (MOD-003-0)
1063. MOD-003-0 requires each regional reliability organization to:
(1) Develop and document a procedure on how a transmission user can
present its 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.
1064. In the NOPR, the Commission identified MOD-003-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and document a procedure on how a transmission
user can present its concerns regarding the TTC and ATC methodologies
of a transmission service provider. The NOPR stated that the Commission
would not propose to approve or remand MOD-003-0 until the ERO submits
additional information.
i. Comments
1065. APPA agrees that MOD-003-0 is a fill-in-the-blank standard.
It notes that it is not sufficient in its current form and should not
be approved as a mandatory Reliability Standard until the accompanying
regional procedures are submitted and approved. In addition, APPA hopes
that if NERC develops the MOD-001-0 Reliability Standard properly, it
will include a reporting procedure for addressing shortcomings in
information for all transmission customers (LSE, generator owner and
purchasing-selling entity) in the MOD-001-0 Standard. APPA argues that,
as a result, MOD-003-0 may be redundant and should be eliminated.
ii. Commission Determination
1066. The Commission adopts the NOPR proposal not to approve or
remand MOD-003-0 until the ERO submits additional information. 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 neither accepts nor
remands 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.
1067. We direct the ERO to consider APPA's suggestion that MOD-003-
0 may be redundant and should be eliminated if the ERO develops a
modification to the MOD-001-0 Reliability Standard through the
Reliability Standards development process that includes reporting
requirements.
f. Documentation of Regional Reliability Organization Capacity Benefit
Margin Methodologies (MOD-004-0)
1068. MOD-004-0 requires each regional reliability organization to:
(1) Develop and document a regional CBM \340\ 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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\340\ The NERC glossary defines ``capacity benefit margin'' or
``CBM'' as the amount of firm transmission transfer capability
preserved by a transmission provider for load serving entities whose
loads are located on the transmission service provider's system, to
enable access by the load serving entity to generation from
interconnected systems to meet generation reliability requirements.
NERC Glossary at 2.
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1069. In the NOPR, the Commission identified MOD-004-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and document a regional CBM methodology. The
NOPR stated that because the regional CBM methodologies had not been
submitted, the Commission would not propose to
[[Page 16521]]
approve or remand MOD-004-0 until the ERO submits the additional
information.
1070. Although not proposing any action, the Commission nonetheless
indicated that MOD-004-0 could be improved by: (1) Providing more
specific requirements on how CBM should be determined and allocated to
interfaces and (2) including a provision ensuring that CBM, TRM and ETC
cannot be used for the same purpose, such as the loss of an identical
generation unit. Further, the Commission expressed concern that the
Reliability Standard may unduly impact competition because of the lack
of consistent criteria and clarity with regard to the entity on whose
behalf CBM has been set aside. This lack of consistent criteria has the
potential to result in the transmission provider's setting aside
capacity that it might not otherwise need to set aside, thus increasing
costs for native load customers and blocking third party uses of the
transmission system.
i. Comments
1071. APPA agrees with the Commission that MOD-004-0 should not be
approved as a mandatory Reliability Standard until the relevant
regional procedures are submitted and approved.\341\
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\341\ APPA notes that it has expressed its own concerns with CBM
calculations and set-asides in its August 7, 2006 Initial Comments
filed in Docket No. RM05-25-000, at 31-55. APPA is hopeful these
concerns can be addressed through NERC's Reliability Standards
development process.
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1072. FirstEnergy states that transmission capacity margins such as
CBM and TRM are vitally important to the reliability of the system, and
any methodology that would unduly limit these margins could create a
danger of limiting transmission capacity over interconnected facilities
that would limit the ability of balancing authorities and others to
obtain generation reserves needed from the grid during contingency
events. In contrast, TAPS questions how TRM or, especially, CBM, can be
viewed as Reliability Standards if they are optional for the
transmission provider.
1073. MidAmerican supports greater uniformity of CBM definitions
and calculations and states that the revised standard and/or new
standards should support transparency and uniformity by encouraging
increased availability of information and consistent data input and
modeling assumptions. EEI emphasizes that additional data and
information-sharing requirements would improve the transparency of
various calculations and assumptions related to CBM, including this
standard and the other CBM-related standards. EEI believes that,
similar to the peer review processes of the planning studies carried
out under the TPL standards, industry participants are best suited to
developing the totality of assumptions, system conditions and other
input variables that support the calculations.
1074. EEI notes that, with respect to the Commission's particular
concern about criteria in determining resources and loads used in the
CBM methodology, NERC's ``ATC Definitions and Determination'' \342\
document clearly delineates the purpose and intent of the calculation
of CBM and TRM. EEI states that CBM is intended to provide generation
reliability, and TRM is intended to provide transmission reliability.
EEI believes that, to the extent capacity capable of supplying CBM is
located in the vicinity of the designated facility experiencing an
outage, transmission may or may not be available under the native load
reservation normally used for the facility. Therefore, EEI argues, CBM
may be needed on an interface where capacity is available for use as
CBM, and not allowing all generation to be considered in this manner
may unduly increase the generation reserve requirement within the
transmission provider's system.
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\342\ NERC, Available Transfer Capability Definitions and
Determination--A Framework for Determining Available Transfer
Capabilities of the Interconnected Transmission Networks for a
Commercially Viable Electricity Market (June 1996).
---------------------------------------------------------------------------
1075. EEI agrees with the Commission's concern about double-
counting TRM for those transmission providers who do not opt to use
CBM. However, EEI argues that for transmission providers who do opt to
use CBM, it may be appropriate in some circumstances to use the same
generation unit outage to determine the impact on both generation and
transmission reliability because the impacts are different. EEI
cautions that artificially restricting such use is not appropriate,
especially before NERC's development of TRM and CBM standards and their
presentation to FERC through the Reliability Standards development
process. EEI recommends that the Commission encourage transmission
providers to make CBM and TRM capacity available to wholesale markets
for purchase on a non-firm basis, because doing so would ensure that
both CBM and TRM capacity are available to the transmission provider
during system emergencies, as intended. EEI notes that at other times
the transfer capability associated with TRM and CBM would be available
to the market, alleviating the concern of possible double-counting.
MidAmerican also supports the Commission's conclusion that double-
counting would be inappropriate, although MidAmerican states that it is
not aware of any cases of double-counting of margins.
1076. TAPS notes the significant potential for abuse \343\ that
could result from the current flexibility afforded transmission
providers in the calculation of CBM and TRM, and proposes innovative
approaches \344\ to take CBM and (to the extent it is intended to cover
transmission required for reserve sharing) TRM out of the hands of
individual transmission providers, and to therefore reduce the
opportunity for abuse.
---------------------------------------------------------------------------
\343\ Documented by NERC's April 14, 2005 Long-Term AFC/ATC Task
Force Final Report.
\344\ TAPS refers the Commission to its August 7, 2006 comments
in Docket No. RM05-25-000 at 21-24.
---------------------------------------------------------------------------
ii. Commission Determination
1077. The Commission adopts the NOPR proposal not to approve or
remand MOD-004-0 until the ERO submits additional information. Because
the regional procedures have not been submitted to the Commission, it
is not possible to 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 neither accepts nor
remands 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.
Consistent with Order No. 890 and comments received in response to the
NOPR, the Commission directs the ERO, through the Reliability Standards
development process, to modify MOD-004-0 as discussed below.
1078. We agree with FirstEnergy that CBM is important for system
reliability by allowing the LSEs to meet their historical, state, RTO
or regional generation reliability criteria requirement such as reserve
margin, loss of load probability, loss of largest units, etc. We agree
with EEI and MidAmerican that transparency of the studies supporting
CBM determination will reduce the opportunity for transmission service
providers to overestimate the amount of CBM and misuse transfer
capability. We therefore direct the ERO to develop Requirements
[[Page 16522]]
regarding transparency of the generation planning studies used to
determine CBM values. We also clarify that CBM should only be set aside
upon request of any LSE within a balancing area to meet its verifiable
historical, state, RTO or regional generation reliability criteria
requirement such as reserve margin, loss of load probability, loss of
largest units, etc. We expect verification of the CBM values to be part
of the Requirements with appropriate Measures and Levels of Non-
Compliance.
1079. We continue to believe this Reliability Standard should be
modified to include a provision ensuring that CBM, TRM and ETC cannot
be used for the same purpose, such as loss of the identical generating
unit. In order to limit misuse of transfer capability set aside as CBM,
we direct the ERO to provide more specific requirements for how CBM
should be determined and allocated across transmission paths or
flowgates. As we stated in Order No. 890, we do not mandate a
particular methodology for allocating CBM to paths or flowgates. For
example, one approach could be based on the location of the outside
resources or spot market hubs that a LSE has historically relied on
during emergencies resulting from an energy deficiency, but we agree
with EEI that flexible rules should be allowed to prevent unnecessary
increase of the generation reserve requirement within the transmission
provider's system. Therefore, we support flexibility, but expect that
the ERO, using its Reliability Standards development process, will
adequately approach these complex technical issues and propose a new
version of MOD-004-0 that addresses the methods for CBM determination
and allocation on paths that will reduce reliability and discrimination
concerns.
1080. In response to TAPS's question asking how CBM can be viewed
as a Reliability Standard if it is optional to the transmission
provider, our understanding is that transmission providers that have
opted not to use CBM have instead set aside transmission margin (needed
to bring in outside power to meet generation reliability criteria)
either through ETC or TRM. CBM is not the only way to reserve
transmission capacity for a margin. However, if the Reliability
Standard is not clear regarding the method of calculating transmission
margins, it may cause double-counting of transmission margins and
reduction of ATC. As we stated in Order No. 890, we find that clear
specification of the permitted purposes for which entities may reserve
CBM and TRM will virtually eliminate double-counting of TRM and CBM.
Therefore, we direct the ERO to modify its standard in order to prevent
setting aside transfer capability for the same purposes.
1081. We share TAPS's concern that there is a significant potential
for abuse as a result of the current flexibility afforded to
transmission providers in the calculation of both CBM and TRM. In
response to TAPS's concern, we clarify that in accordance with the OATT
Reform Final Rule and the ERO CBM definition, each LSE has the right to
request CBM be set aside and use it to meet its verifiable historical,
state, RTO or regional generation reliability criteria requirement such
as reserve margin, loss of load probability, loss of largest units,
etc. As such, the LSEs that request CBM be set aside must be identified
as applicable entities with identified Requirements, including
Requirements on generation studies to verify the set aside, Measures
and Levels of Non-Compliance. We direct the ERO to modify the
Reliability Standard accordingly.
1082. We agree with TAPS that there is a need for clearer
requirements in the standard regarding to whom and how to submit a
request for CBM set-aside, and what the transmission service provider
should do if the sum of all CBM requirements exceeds the amount of
available transfer capability. We direct the ERO to address the
reliability aspects in the Reliability Standards development process
and explore with NAESB whether business practices would be required.
1083. Accordingly, the Commission neither accepts nor remands MOD-
004-0 until the ERO submits additional information. 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. Although the Commission did not
propose any action with regard to MOD-004-0, it addressed above a
number of concerns regarding the Reliability Standard, consistent with
those set forth in Order No. 890. Therefore, we direct the ERO to
develop modifications to the Reliability Standard through the
Reliability Standards development process to: (1) Clarify that CBM
shall be set aside upon request of any LSE within a balancing area to
meet its verifiable historical, state, RTO or regional generation
reliability criteria; (2) develop requirements regarding transparency
of the generation planning studies used to determine CBM value; (3)
modify the current Requirements to make clear the process for how CBM
is allocated across transmission paths or flowgates; (3) modify its
standard in order to prevent setting aside CBM and TRM for the same
purposes; (4) modify the standard by adding LSE as an applicable entity
and (5) coordinate with NAESB business practice standards.
1084. We direct the ERO to consider APPA's suggestion that MOD-004-
0 may be redundant and should be eliminated if the ERO develops a
modification to the MOD-002-0 Reliability Standard that includes
reporting requirements
g. Procedure for Verifying Capacity Benefit Margin Values (MOD-005-1)
1085. MOD-005-1 specifies the requirements regarding the periodic
review of a transmission service provider's adherence to the regional
reliability organization's CBM methodology. It requires each regional
reliability organization to: (1) Develop and implement a procedure to
review at least annually the CBM calculations and the resulting values
determined by member transmission service providers; (2) document its
CBM review procedure and (3) make the results of the most current CBM
review available to NERC upon request.
1086. In the NOPR, the Commission identified MOD-005-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and implement a procedure to review CBM
calculations and the resulting values and to make the documentation of
the results of the CBM review available to NERC and others. The NOPR
stated that because the regional procedures had not been submitted, the
Commission would not propose to approve or remand MOD-005-0 until the
ERO submits the additional information.
i. Comments
1087. APPA agrees that MOD-005-0 is a fill-in-the blank standard,
and that in its current form, it is not sufficient and should not be
accepted for approval as a mandatory Reliability Standard until the
necessary regional procedures have been submitted and approved. APPA
suggests that NERC modify MOD-006-0, so that MOD-004-0 and MOD-005-0
could be eliminated.
ii. Commission Determination
1088. The Commission adopts the NOPR proposal not to approve or
remand MOD-005-0 until the ERO submits additional information. 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,
[[Page 16523]]
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' Accordingly, the Commission neither accepts nor
remands this Reliability Standard until the regional procedures are
submitted. 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.
1089. As to APPA's comment on incorporating MOD-004 and MOD-005
into MOD-006, we direct the ERO to consider those comments through the
Reliability Standards development process.
h. Procedure for Use of Capacity Benefit Margin Values (MOD-006-0)
1090. The purpose of MOD-006-0 is to promote the consistent and
uniform use of transmission CBM calculations among transmission system
users. MOD-006-0 requires that each transmission service provider
document its procedure for the scheduling of energy against a CBM
reservation and make the procedure available on a Web site accessible
by the regional reliability organization, NERC and transmission users.
1091. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-006-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to 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 LSEs.
1092. In addition, the Commission proposed 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. The
Commission provided guidance expressing its belief that CBM should be
used only when the LSE's local generation capacity is insufficient to
meet balancing Reliability Standards, and that CBM should have a zero
value in the calculation of non-firm ATC.
i. Comments
1093. APPA supports the Commission's proposal to approve MOD-006-0.
Moreover, APPA agrees with the Commission's proposed directives \345\
that the standard should address the use of CBM and TRM for the same
purpose. However, APPA believes that the specificity of the
Commission's proposed directives to NERC, if implemented, would
undermine NERC's role as the approved ERO with the technical expertise
to develop and revise standards for the Commission's subsequent review.
APPA therefore suggests that the Commission in its Final Rule make
clear to NERC its concerns about MOD-006-0, but then let NERC address
those concerns through its Reliability Standard development process.
---------------------------------------------------------------------------
\345\ NOPR at P 642.
---------------------------------------------------------------------------
1094. Regarding the Commission's proposal that MOD-006-0 R1.2 be
modified ``so that concurrent occurrence of transmission constraints
and a generation deficiency is not a requirement for CBM usage,'' WEPCO
asserts that the Commission is misinterpreting CBM. WEPCO states that
if there is no transmission constraint then there is no need to use
CBM. In that case, transmission capacity exists for a LSE to import
energy. If there is a transmission constraint, CBM reserves
transmission capacity that the LSE can use to import energy for
reliability needs.
1095. EEI points out that the explicit intention for CBM is that it
be used only during conditions where there are emergency generation
deficiencies. However, EEI emphasizes that the Commission's
recommendation does not consider that the LSE's supply and demand
balance varies season to season, over time, and with supply and demand
uncertainties. EEI says that the development of CBM quantities must be
carried out in a manner that sets aside transmission capability for
forecasted conditions and uncertainties much like the native load
reservations necessary for serving reasonably-forecasted native load.
An argument may be made that during a period of time when a LSE's
expected reserves are substantially greater than its targeted reserves,
the need for CBM set-aside decreases. However, should the LSE foresee
that this ``excess'' would occur substantially in the future, a
reduction in CBM would not be warranted since substantial uncertainties
still exist.
1096. Additionally, regarding the Commission's proposal that a LSE
that ``has sufficient generation resources within its balancing
authority to meet the balancing Reliability Standards, should not need
to preserve capacity for CBM at all,'' WEPCO argues that just because
the balancing authority has sufficient generation does not mean that
there is sufficient transmission capacity to deliver the energy to the
LSE. WEPCO states that the LSE may be remote from the bulk of the
balancing authority, so there may be occasions when a LSE that has
sufficient generation resources within its balancing authority to meet
the balancing Reliability Standards may still need to reserve capacity
for CBM. In addition, EEI argues that the Commission's viewpoint does
not take into account the availability of these resources unless they
are under contract with the LSE to provide this service. EEI contends
that the implication of this suggestion is to unduly restrict the
sources of generation capacity available for CBM during times of
generation shortage, which results in the LSE's being captive to local
generation that is available and does not allow access to the market
outside of the LSE's balancing authority. Additionally, EEI cautions
that this action may require the LSE to develop contractual agreements
with local generation and thus increase costs to the LSE's rate payers.
1097. Given the strong direction on CBM issues in the OATT Reform
NOPR, TAPS assumes that the Commission would not be approving the
Version 0 standards on these competitively crucial issues, but would
continue to address them forcefully in the OATT Reform proceeding. TAPS
notes that, although that is the course largely adopted by the NOPR in
this proceeding, the NOPR \346\ proposes to approve MOD-006-0 and MOD-
007-0, with directions to improve these standards. TAPS notes that such
action is inconsistent with the Commission's general approach to ATC/
TTC/TRM/CBM standards in this docket and the OATT Reform NOPR. TAPS
further states that, given the absence of clear access of non-
transmission owner LSEs to CBM, the proposed expansion of MOD-007-0 to
include such LSEs in the NOPR \347\ seems bizarre.
---------------------------------------------------------------------------
\346\ Id. at P 642, 648.
\347\ Id. at P 647-48.
---------------------------------------------------------------------------
ii. Commission Determination
1098. The Commission adopts the NOPR proposal to approve MOD-006-0
as mandatory and enforceable. Consistent with Order No. 890 and
comments received in response to the NOPR, the Commission directs the
ERO to modify MOD-006-0 as discussed below.
1099. Consistent with the views of many commenters, we adopt the
NOPR proposal that requires a provision that will ensure that CBM and
TRM are not used for the same purpose. As discussed under MOD-004-0
concerning the
[[Page 16524]]
reservation of transfer capacity, we believe that if the Reliability
Standard is not clear regarding the conditions specifying both the
reservation and the use of CBM, it may cause double-counting. Such
double-counting will lead to an unnecessary reduction of ATC, and
create opportunities for discrimination. Therefore, we direct the ERO
to modify its standard to prevent use of CBM and TRM for the same
purposes. We agree with APPA that the ERO should use its Reliability
Standards development process to address the double-counting problem.
1100. We adopt the NOPR's proposal and direct the ERO to modify
Requirement R1.2 so that a transmission constraint is not a required
condition for CBM usage. The glossary definition and the use as defined
in Order No. 890 is that CBM ``is intended to be used by the LSE only
in time of emergency generation deficiencies.'' \348\ Therefore we
direct the ERO to modify the standard in the manner proposed in the
NOPR.
---------------------------------------------------------------------------
\348\ See NERC Glossary at 2.
---------------------------------------------------------------------------
1101. We adopt the NOPR proposal that requires modification of
Requirement R1.2 to define ``generation deficiency'' based on a
specific energy emergency alert level. This approach will provide
clarity as to when the use of CBM may be permitted. We therefore direct
the ERO to modify the Reliability Standard to include a specific energy
emergency alert level that will trigger CBM usage.
1102. We also reiterate the direction in Order No. 890 that CBM
should have a zero value in the calculation of non-firm ATC because
non-firm service may be curtailed so that CBM can be used. CBM is
reserved as part of the firm transfer capability so that it is
available when needed for energy emergencies. We determine that each
LSE should be permitted to call for use of CBM, provided all of the
other Requirements of R1.1 are met. We direct that CBM may be
implemented up to the reserved value when a LSE is facing firm load
curtailments.
1103. We adopt the NOPR proposal that CBM should be used only when
the LSE's local generation capacity is insufficient to meet balancing
Reliability Standards, with the clarification that the local generation
is that generation capacity that is either owned or contracted for by
the LSE. We disagree with WEPCO that just because the balancing
authority has sufficient generation does not mean that there is
transmission capacity to deliver the energy to the LSE. The Commission
finds that such a scenario would violate existing transmission
operating and transmission planning Reliability Standards. There is an
explicit requirement in the transmission operating standards that
generation reserves must be deliverable to load.\349\ Also, there is an
explicit requirement in the transmission planning standards that all
firm load must be supplied under various system conditions with and
without contingencies.\350\ The Commission is not prescribing how these
requirements should be met. There are a variety of approaches to do so,
including adequate transmission capability, local or dynamic generation
transfers into the area or DSM. To clarify for EEI, our proposal does
not take into account the availability of these resources unless they
are under contract with the LSE to provide this service. We developed
our NOPR proposal on the rationale derived from the CBM concept, and
believe that if there are enough resources to meet generation
reliability criteria within the balancing authority, there is no need
to request CBM.
---------------------------------------------------------------------------
\349\ TOP-002-2.
\350\ TPL-002-0.
---------------------------------------------------------------------------
1104. We also adopt the NOPR proposal to require the applicability
section to include the entities that actually use CBM, such as LSEs.
The current CBM definition in the NERC glossary determines that LSEs
are users of CBM. Load-serving entities determine when to use CBM,
initiate CBM use and call for its end. Load-serving entities therefore
have to comply with the standard requirements that specify the
conditions under which CBM will be used. We direct the ERO to modify
the standard accordingly.
1105. With regard to TAPS's comments concerning its assumption that
the Commission would not be approving the Version 0 standards on these
issues, but would continue to address them in the OATT Reform
proceeding, the Commission finds that MOD-006-0 and MOD-007-0 do not
establish CBM values, but rather address CBM implementation and
documentation. The implementation of CBM has critical implications for
the reliable operation of the Bulk-Power System and we find that these
Reliability Standards should be mandatory and enforceable. The
competitively significant issue is to assure that there is no double-
counting of CBM and to determine the magnitude of CBM which is
addressed in other Reliability Standards that the Commission has not
approved or remanded.
1106. The Commission approves MOD-006-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a
modification to Reliability Standard MOD-006-0 through the Reliability
Standards development process that: (1) Includes a provision that will
ensure that CBM and TRM are not used for the same purpose; (2) provides
that CBM should be used for emergency generation deficiencies; (3)
modifies Requirement R1.2 to define ``generation deficiency'' based on
a specific energy emergency alert level; (4) includes a provision that
CBM should have a zero value in the calculation of non-firm ATC and (5)
expands the applicability section to include the entities that actually
use CBM, such as LSEs.
i. Documentation of the Use of Capacity Benefit Margin (MOD-007-0)
1107. MOD-007-0 requires transmission service providers that use
CBM to report and post its use.
1108. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-007-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-007-
0 that expands the applicability section to include the entities that
actually use CBM, such as LSEs.
i. Comments
1109. APPA supports the Commission's proposed approval of MOD-007-
0. However, it believes that the issue of whether LSEs should be made
subject to MOD-007-0 should be left to NERC in the first instance to
decide. In so doing, NERC should consider expanding MOD-007-0 to cover
not only LSEs, but also balancing authorities. Under NERC's Functional
Model, the balancing authority is the entity that would schedule energy
over transmission capacity reserved as CBM. Moreover, it is the
balancing authority that would know the information necessary to report
an incident during which the balancing authority had to import energy
from outside the balancing authority's own area from a resource
designated as operating reserves and change the net scheduled
interchange with the neighboring balancing authorities to allow the
energy to flow into the balancing authority's area.
ii. Commission Determination
1110. The Commission approves MOD-007-0 as mandatory and
enforceable. Consistent with the comments received in response to the
NOPR, the Commission directs the ERO
[[Page 16525]]
to modify the standard as discussed below.
1111. We also adopt the NOPR's proposal to require the
applicability section to include the entities that actually use CBM and
report on their CBM use, such as LSEs. The current CBM definition in
the NERC glossary determines when a LSE is a CBM user. The LSE
determines how much CBM will be set aside, when CBM use will start and
when it will end. The LSE must therefore comply with the standard
requirements that require reporting and posting of CBM use. We direct
the ERO to modify the standard to include the entities that actually
use CBM, such as LSEs. In addition, we agree with APPA that the
Reliability Standard should apply to balancing authorities and direct
the ERO to include balancing authorities within the entities to which
this standard is applicable.
1112. Accordingly, the Commission approves MOD-007-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification through its Reliability Standards development process
that expands the applicability of MOD-007-0 to include the entities
that actually use CBM, such as LSEs and balancing authorities.
j. Documentation and Content of Each Regional Transmission Reliability
Margin Methodology (MOD-008-0)
1113. MOD-008-0 requires the development and posting of a regional
methodology for TRM, which is transmission capacity that is reserved to
provide reasonable assurance that the interconnected transmission
network will remain secure under various system conditions. The
Reliability Standard requires each regional reliability organization
to: (1) Develop and document a regional TRM methodology in conjunction
with its members and (2) post on a Web site the most recent version of
its TRM methodology.
1114. In the NOPR, the Commission identified MOD-008-0 as a fill-
in-the-blank standard, proposing that because the regional
methodologies had not been submitted, the Commission would not propose
to approve or remand MOD-008-0 until the ERO submitted the additional
information. The Commission expressed concern about the lack of: (1)
Clear requirements on how TRM should be calculated and allocated across
paths and (2) consistent criteria and clarity with regard to the entity
on whose behalf TRM had been set aside.
1115. The Commission requested comment in the NOPR on how TRM is
currently calculated and allocated across paths, and what would be a
recommended approach for the future.
i. Comments
1116. APPA agrees that MOD-008-0 is a fill-in-the-blank standard,
is not sufficient as currently drafted, and should not be approved as a
mandatory Reliability Standard until NERC and the regional reliability
organizations and regional entities develop the necessary regional
methodologies and the Commission approves them.
1117. MISO adds that there should be a consistent framework to be
followed by entities in determining TRM. It states that relevant MOD
standards should be revised if such a framework is not clearly
delineated. However, MISO cautions that a Reliability Standard should
not be used to address a perceived equity concern. MidAmerican also
supports greater uniformity of TRM definitions and calculations, and
proposes that a revised standard and/or new standards should encourage
transparency with increased availability of information, consistent
data input and certain modeling assumptions. International Transmission
agrees and proposes that TRM consistency should be addressed either on
a regional basis or on an Interconnection-wide basis.
1118. In response to the Commission's request for comments on the
current calculation of TRM, and recommended approaches for the future,
International Transmission provides a description of the MISO approach
to TRM. International Transmission states that during the operating
horizon (next 48 hours), TRM is limited to a reserve sharing component
which only applies to flowgates that are not based on transmission
outages (unit tripping and transmission outages are considered a double
contingency). International Transmission states that the logic behind
this approach is that there are fewer uncertainties in the operating
horizon because schedules and market flows are known. International
Transmission explains that during the planning horizon (next 48 hours),
a two percent TRM component for uncertainty is used on all flowgates,
including those requiring reserve sharing TRM. In addition, other
assumptions regarding the sale of transmission service enter into the
need for TRM to cover ``uncertainties.'' In addition, International
Transmission cautions that MISO's minimal two percent margin may not be
sufficient for long-term planning horizon requests (i.e., over 13
months) if planning ``assumptions'' are not reasonable. International
Transmission argues that MISO must also employ proper sensitivity
studies to other system variables for a two percent margin to be
sufficient. TRMs in the five to ten percent range are not necessarily
unreasonable if a wide range of potential system operating conditions
is not studied. Regardless of the ultimate approach adopted in future
standards, International Transmission proposes that all entities follow
a consistent framework when calculating TRM.
1119. MidAmerican responds with a discussion of its current
approach to TRM calculation, which has been performed in accordance
with MAPP-approved methodologies. MidAmerican states that these
methodologies include an amount to allow for both the delivery of
operating reserves and for uncertainties. Since delivery of operating
reserves keeps the interconnected network in service, benefiting all
market participants, MidAmerican contends that it is appropriate for
TRM to include an amount to allow for the delivery of operating
reserves. The allowance for uncertainty is calculated as a percentage
of TTC required to protect reliability. All market participants benefit
from the provision of an appropriate margin for uncertainty because the
reliability of the interconnected network is maintained and service
interruptions are reasonably minimized.
1120. With respect to applicable entities, APPA proposes the
addition of two new functional entities. Specifically, APPA believes
that NERC should expand the applicability section of MOD-008-0 to
include planning authorities and reliability coordinators. APPA points
out that these are the only entities that can evaluate the amount of
error in their transfer capability predictions.
1121. ERCOT states that the Commission's concerns about TRM do not
apply to ERCOT, because ERCOT has a balanced grid in which all
transmission is firm, no transmission is reserved and there are no
transmission paths.
ii. Commission Determination
1122. The Commission does not approve or remand MOD-008-0 until the
ERO submits additional information. Consistent with Order No. 890 and
comments received in response to the NOPR, the Commission directs the
ERO to modify MOD-008-0 through the Reliability Standards development
process, as discussed below.
1123. Consistent with the NOPR proposal and Order No. 890, the
Commission directs the ERO to modify standard MOD-008-0 to clarify how
TRM should be calculated and allocated
[[Page 16526]]
across paths or flowgates. We understand that the standards drafting
process is underway as a joint project with NAESB. We agree with
International Transmission, MidAmerican and MISO about the need for
more uniformity and transparency in TRM calculation methodology and
use, in order to eliminate potential reliability and discrimination
concerns. Consistent with Order No. 890, the Commission directs the ERO
to specify the parameters for entities to use in determining
uncertainties for which TRM can be set aside and used, such as: (1)
Load forecast and load distribution error; (2) variations in facility
loadings; (3) uncertainty in transmission system topology; (4) loop
flow impact; (5) variations in generation dispatch; (6) automatic
reserve sharing and (7) other uncertainties as identified through the
NERC Reliability Standards development process. We find that clear
specification in this Final Rule of the permitted purposes for which
entities may reserve CBM and TRM will also virtually eliminate double-
counting of TRM and CBM. Therefore, we direct the ERO to determine
clear requirements regarding permitted uses for TRM through its
Reliability Standards development process.
1124. We agree with the commenters that the percentage reduction of
line rating can be one way to establish an appropriate maximum TRM if
thermal considerations are the only limiting factors. While this is a
relatively simple method, it ignores limitations relative to voltage or
stability limitations which are the more typical reasons for
transmission limitations. If adopted as the Reliability Standard
method, it should not restrict a transmission provider from using a
more sophisticated method that may allow for greater ATC without
reducing overall reliability. However, we disagree with the use of an
arbitrary percentage over a long time frame that is not based on either
proven historical need or sensitivity studies that support that
determination. Therefore, consistent with our OATT Reform Final Rule,
we direct the ERO to develop requirements regarding transparency of the
documentation that supports TRM determination.
1125. We agree with APPA that NERC should revise the applicability
section of this standard to add planning authorities and reliability
coordinators, and in addition, any other entities that may be
identified in the Reliability Standards development process.
1126. Regarding ERCOT's statement that TRM does not apply to ERCOT,
we reiterate our position that any request for a regional exemption
from the applicable Reliability Standards must take place in the
Reliability Standards development process.
1127. The Commission neither accepts nor remands MOD-008-0 until
the ERO submits additional information. In the interim, compliance with
MOD-008-0 should continue on a voluntary basis, and the Commission
considers compliance with the Reliability Standard to be a matter of
good utility practice. Although the Commission did not propose any
action with regard to MOD-008-0, it addressed above a number of
concerns regarding the Reliability Standard, consistent with those
proposed in Order No. 890. Accordingly, we direct the ERO to develop
modifications to the Reliability Standard through the Reliability
Standards development process including: (1) Clear requirements on how
TRM should be calculated, including a methodology for determining the
maximum TRM value, and allocated across paths; (2) clear requirements
for permitted purposes for which TRM can be set aside and used; (3)
clear requirements for availability of documentation that supports TRM
determination and (4) expanding the applicability to add planning
authorities and reliability coordinators and any other appropriate
entity identified in the Reliability Standards development process.
k. Procedure for Verifying Transmission Reliability Margin Values (MOD-
009-0)
1128. MOD-009-0 requires 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.
1129. In the NOPR, the Commission identified MOD-009-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop a procedure for review of TRM calculations and
the resulting values. In the NOPR, the Commission stated that because
the regional procedures had not been submitted, the Commission would
not propose to approve or remand MOD-009-0 until the ERO submits the
additional information.
i. Comments
1130. APPA agrees that MOD-009-0 is a fill-in-the-blank standard,
is not sufficient as currently drafted, and should not be approved as a
mandatory Reliability Standard until NERC and the regional reliability
organizations and regional entities develop the necessary regional
methodologies and the Commission approves them.
ii. Commission Determination
1131. The Commission will not approve or remand MOD-009-0 until the
ERO submits additional information. 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 neither approves nor remands
this Reliability Standard until the regional procedures are submitted.
In the interim, compliance with MOD-009-0 should continue on a
voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice.
l. Steady-State Data for Modeling and Simulation of Interconnected
Transmission System (MOD-010-0)
1132. The purpose of this Reliability Standard is to establish
consistent data requirements, reporting procedures and system models
for use in 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 other specified entities.
1133. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-010-0 as mandatory and enforceable. In addition, the
Commission proposed to direct 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.
i. Comments
1134. APPA agrees with the Commission that MOD-010-0 is sufficient
for approval as a mandatory and enforceable Reliability Standard. APPA
believes, however, that the Commission's proposed directives to NERC to
revise this standard are unduly prescriptive, and may not in fact be
the best way to revise the standard.
1135. ISO/RTO Council and ISO-NE do not support adoption of this
standard because its requirements refer several
[[Page 16527]]
times to the data requirements and reporting procedures specified in
MOD-011-0, which has been identified by the Commission as a fill-in
the-blank standard. ISO/RTO Council and ISO-NE argue that demonstrating
compliance with MOD-010-0 is dependent on an unapproved standard, that
the unapproved standard lacks some required criteria or procedures that
must be developed by the regional reliability organization, that MOD-
010-0 cannot be effectively implemented, and that responsible entities
therefore should not be subject to compliance with an incomplete
standard.
1136. Constellation strongly supports the Commission's proposals
with respect to MOD-010-O and MOD-012-0 because these proposals,
together with other initiatives, such as OATT reform, represent
additional steps not only to achieving a reliable bulk power system,
but also to reducing undue discrimination in transmission services.
Constellation supports the Commission's proposals because they will
involve generation owners in facility ratings discussions and
discussions of other limiting components and will provide more clarity
in the requirements of the Reliability Standard, making enforcement
more objective and robust.
1137. Many commenters submitted comments both supporting and
opposing the Commission's proposal to modify the standard to require
listing the contingencies that transmission owners use when they
perform system operation and planning studies.
1138. FirstEnergy supports the Commission's proposal to require
transmission owners to provide the list of contingencies used in
performing system operation and planning studies. FirstEnergy
emphasizes that such a requirement, however, should accommodate various
electronic formats that are commonly used in industry simulation tools.
FirstEnergy states that compliance with this Reliability Standard
should not require transmission owners to replace existing computer
and/or software systems, and that the new standard should also require
the regional reliability organizations (or Regional Entities) to
coordinate the lists of contingencies across wide-areas.
1139. In its support of the Commission's proposal, MidAmerican and
TANC stress that a requirement that the transmission owner provide a
list of contingencies to neighboring systems will benefit reliability
by enabling neighboring systems to accurately study the effects of
contingencies on their own systems. In its concurring comments, TANC
recommends that the Commission clarify that the list of the
contingencies that are used in performing system operation and planning
studies include all the contingencies, N-1, N-2, as well as multiple
contingencies.
1140. MidAmerican cautions that a list of contingencies could be
used in a ``cook-book'' manner to reach the wrong conclusions. A
contingency must be modeled in specific and appropriate conditions to
understand the reliability issues associated with the contingency.\351\
Similarly, NERC states that there may be a need to better understand
the reliability need for transmission owners to provide a list of
contingencies and to whom the list should be provided.
---------------------------------------------------------------------------
\351\ MidAmerican further cautions that other contingencies
exist that must be studied under still-different conditions.
Advanced applications associated with real-time contingency analysis
review an extensive list of events in combination with other events.
Ahead of time, there is no way to be sure exactly which events are
the worst in any given operating condition. A single reliability
standard cannot contain all the coordination that is needed to allow
a system to fully understand all the reliability challenges of a
neighboring system. Thus, MidAmerican contends that a better
approach is to continue the joint operational and long-term planning
that planning authorities, reliability coordinators and other
regional entities are currently conducting with transmission
planners, transmission owners and others to ensure that the
interconnected network is operated and planned in a coordinated way.
---------------------------------------------------------------------------
1141. Northern Indiana and MidAmerican note that such a list of
contingencies should be considered a particularly sensitive form of
CEII since it would be a list of events that, when they occur, cause
critical situations on a system. Northern Indiana and MidAmerican argue
that the Commission should include the need to provide for protection
against public disclosure through the NERC administrative process in
its discussion of any final Reliability Standard. In addition,
California Cogeneration states that Requirements R1 and R2 of this
standard should not apply to entities that have no material impact on
the grid. California Cogeneration warns that the standard may also
require generator owners to provide data on behind-the-meter
operations, the provision of which should be seriously limited, and
data on future interchange schedules, the confidentiality of which
should be maintained.
1142. PG&E and Xcel oppose the proposed modification requiring a
list of contingencies stating that the requirement is unnecessary and
would be unduly burdensome. Xcel also states that the modification
would not prove to be useful to neighboring systems. No such lists are
currently developed or maintained today. Rather, the contingencies are
reflected in the computerized models used by transmission providers for
both transmission planning and operations. The models are regularly
updated as new facilities are installed. If transmission operators are
required to develop such lists, they would be so long and subject to
constant change that they would not only be burdensome to develop and
maintain, but also unlikely to provide useful information for other
transmission owners.
1143. In its opposition to releasing a list of contingencies, PG&E
states that performing transmission planning studies is an ambiguous
part of the duties of a transmission owner under the NERC Functional
Model. Further clarification and refinement of the responsibilities of
each entity under the NERC Functional Model may indicate that such
studies are among a transmission owner's duties. Until that happens,
however, requiring transmission owners to provide contingencies used in
performing system operation and planning studies is inappropriate.
1144. SoCal Edison and TVA state that the entity that should be
responsible for providing a list of contingencies in performing
planning and operation studies is the transmission planner, not the
transmission owner. APPA also believes that the transmission operator
should be one of the entities required to list contingencies used to
perform studies, and that the transmission owner function should be
removed as an applicable entity. APPA further notes that the
transmission owner does no studies regarding operations or planning. A
transmission owner merely owns transmission facilities and maintains
those facilities. Moreover, APPA argues that existing studies performed
by the transmission planner for the regional reliability organization
or planning authority will include a list of contingencies.
1145. Regarding the Commission's proposal to expand the
applicability section of this Reliability Standard to include the
planning authority, APPA disagrees and recites the comments of MRO,
Reliability First and PG&E on the Staff Preliminary Assessment,\352\
that to require the planning authority to provide all of this
information is duplicative and unnecessary. APPA believes that NERC, as
the entity charged with developing standards, is best-suited to address
all of these
[[Page 16528]]
concerns and to develop a consensus standard using its Reliability
Standard development process.
---------------------------------------------------------------------------
\352\ NOPR at P 663.
---------------------------------------------------------------------------
1146. TAPS states that this standard would impose unnecessary costs
on small systems without improving reliability if applied without the
limitation of NERC's bulk electric system definition and NERC's June
registry criteria. TAPS opines that modeling will be complicated by the
incorporation of low voltage or radial transmission facilities or small
generators that have no material impact on bulk transmission system
reliability, without improving the results. TAPS further argues that
NERC and the Regional Entities--not the Commission--should determine
the level of modeling required for reliability.
ii. Commission Determination
1147. The Commission approves MOD-010-0. In addition, the
Commission requires the ERO to modify MOD-010-0 as described below.
1148. As an initial matter, the Commission disagrees that MOD-010-0
cannot be implemented until MOD-011-0 is modified. We have directed
that data collection and reporting procedures not be interrupted while
MOD-011-0 is being modified. Therefore it is possible to implement MOD-
010-0. Failure to have the data needed for the steady-state analysis
would halt regional reliability assessment processes and hinder
planners from accurately predicting future system conditions, which
would be detrimental to system reliability. We therefore 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 Entity
the information related to data gathering, data maintenance,
reliability assessments and other process-type functions. As we discuss
below in the section on MOD-011-0, we direct the ERO to develop a Work
Plan that will facilitate ongoing collection of the steady-state
modeling and simulation data set forth in MOD-011-0, and submit a
compliance filing with that Work Plan.
1149. Supported by many commenters, we adopt the NOPR proposal to
direct the ERO to modify MOD-010-0 to require filing of all of the
contingencies that are used in performing steady-state system operation
and planning studies. We believe that access to such information will
enable planners to accurately study the effects of contingencies
occurring in neighboring systems on their own systems, which will
benefit reliability. Because of the lack of information on contingency
outages and the automatic actions that result from these contingencies,
planners have not been able to analyze neighboring conditions
accurately, thereby potentially jeopardizing reliability on their own
and surrounding systems. This requirement will make transmission
planning data more transparent, consistent with Order No. 890 requiring
greater openness of the transmission planning process.
1150. With respect to TANC's recommendation to modify the standard
to require utilities to provide lists of all contingencies they use to
operate and plan their systems (N-1, N-2, multiple), we clarify that
our requirement specifies contingency files used for all operations and
planning. We do not limit the provision of contingency information to
single, double or multiple outages. Utilities must provide lists of all
the contingencies they use in operations and planning, provided in
their original format, regardless of how this data is organized.
1151. In response to MidAmerican, NERC and TANC's concerns that the
contingency lists could be used as a ``cook-book,'' our expectation is
that utility planners that use these files will have sufficient
experience to use them appropriately. We expect that most utility
planners are already familiar with their neighbors' system topologies,
and have the means, such as bus abbreviation directories and switching
diagrams, to identify facilities listed in contingency files.
1152. We agree with FirstEnergy's comments regarding the importance
of using existing data collection systems so as to not impose any
additional costs on entities. They may file the contingency files in
the electronic format in which they were created, along with any
necessary decoding instructions. We therefore disagree with PG&E, TAPS
and Xcel that this Reliability Standard will be unduly burdensome since
it only requires the provision of files that must be developed during
the utility's usual planning and operations study process.
1153. Consistent with California Cogeneration, Northern Indiana and
MidAmerican's concerns, we determine that those data that a company
considers confidential, commercially-sensitive or security-sensitive
should be released in accordance with the CEII process or subject to
confidentiality agreements. We direct the ERO to address
confidentiality issues and modify the Reliability Standard as necessary
through its Reliability Standards development process.
1154. We disagree with commenters that generators or small entities
that do not have a material impact on grid reliability should be
automatically exempt from providing the data required by this
Reliability Standard. The Commission believes that all entities that
are required to register under the registration process that we have
approved must provide data requested by the ERO or the Regional Entity.
1155. We agree with APPA, SoCal Edison and TVA that the functional
entity responsible for providing the list of contingencies in
performing planning studies should be the transmission planner, instead
of the transmission owner, as proposed in the NOPR. We also agree with
APPA that the transmission operator should be one of the entities
required to list contingencies used to perform operational studies.
Transmission operators are usually responsible for compiling the
operational contingency lists for both normal and conservative
operation. Therefore, we direct the ERO to modify MOD-010-0 to include
transmission operators as an applicable entity.
1156. We adopt our NOPR proposal that the planning authority should
be included in this 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. We
disagree with APPA that it is duplicative and unnecessary to require
the planning authority to provide all of this information. However, we
direct the ERO, as the entity charged with developing Reliability
Standards, to address all of these concerns and to develop a consensus
standard using its Reliability Standard development process.
1157. Accordingly, the Commission approves MOD-010-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification to MOD-010-0 through the Reliability Standards
development process that: (1) Adds a new requirement in MOD-010-1 for
transmission planners to provide the contingency lists they use in
performing system operation and planning studies, contained in the
electronic format in which they were created, along with any necessary
decoding instructions and (2) expands the applicability section to
include transmission operators and the planning authority. We also
direct the ERO to address confidentiality and small entity issues
through the Reliability Standards development process.
[[Page 16529]]
m. Maintenance and Distribution of Steady-State Data Requirements and
Reporting Procedures (MOD-011-0)
1158. The purpose of MOD-011-0 is to establish consistent data
requirements, reporting procedures and system models for use in
reliability analysis. This Reliability Standard requires the regional
reliability organizations to develop comprehensive steady-state data
requirements and reporting procedures needed to model and analyze the
steady-state conditions for each Interconnection.
1159. In the NOPR, the Commission identified MOD-011-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop comprehensive steady-state data requirements
and reporting procedures needed to model and analyze the steady-state
conditions for each Interconnection. The NOPR stated that because the
regional methodologies had not been submitted, the Commission would not
propose to approve or remand MOD-011-0 until the ERO submits the
additional information. In addition, the NOPR suggested that the
planning authority plays a significant role in integration of data and
thus should be included in the applicability section of MOD-011-0.
i. Comments
1160. APPA agrees with the Commission that this standard is a fill-
in-the-blank standard, is not sufficient as currently drafted and
should not be approved as a mandatory reliability standard until NERC
and the Regional Entities develop the necessary methodologies and the
Commission approves them.
1161. TANC supports replacing the term regional reliability
organization with an entity from the NERC Functional Model.
ii. Commission Determination
1162. The Commission will not approve or remand MOD-011-0 until the
ERO submits additional information. The Commission directs the ERO to
modify MOD-011-0 as discussed below.
1163. We reiterate our position stated in the NOPR that the
planning authority should be included in this Reliability Standard
because the planning authority is the entity responsible for the
coordination and integration of transmission facilities and resource
planning, as well as one of the entities responsible for the integrity
and consistency of the data. Therefore, we direct the ERO to add the
planning authority to the applicability section of this Reliability
Standard.
1164. In response to concerns raised in MOD-010-0 about
implementing MOD-010-0 without the data to be collected when MOD-011-0
is modified, we direct the ERO to develop a Work Plan that will
facilitate ongoing collection of the steady-state modeling and
simulation data specified in MOD-011-0.
1165. Accordingly, the Commission neither accepts nor remands MOD-
011-0 until the ERO submits additional information. Because the
regional procedures 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.'' In the interim, compliance with MOD-011-0 should
continue on a voluntary basis, and the Commission considers compliance
with the Reliability Standard to be a matter of good utility practice.
We direct the ERO to modify the Reliability Standard through the
Reliability Standards development process to expand the applicability
section to include the planning authority. Additionally, we direct the
ERO to develop a Work Plan and submit a compliance filing that will
facilitate ongoing collection of the steady-state modeling and
simulation data specified in MOD-011-0.
n. Dynamics Data for Modeling and Simulation of the Interconnected
Transmission System (MOD-012-0)
1166. The purpose of MOD-012-0 is to establish consistent data
requirements, reporting procedures and system models for use in
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 other specified entities.
1167. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-012-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to 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 dynamics
system modeling analysis for system operation and planning and (2)
expands the applicability section to include the planning authority.
i. Comments
1168. APPA and PG&E agree that the Commission should approve MOD-
012-0 as a mandatory and enforceable Reliability Standard. However,
PG&E requests the Commission to approve this standard without any
modifications. In addition, APPA states that the Commission's proposed
directives to NERC to revise this standard are unduly prescriptive, and
may not in fact be the best way to revise the standard. APPA notes that
NERC, as the technical expert body charged with developing standards,
is the entity best suited to hear all of these concerns, and to develop
a consensus standard using its Reliability Standards development
process.
1169. ISO/RTO Council and ISO-NE disagree with the Commission's
proposal to approve this standard, and state that the MOD-012-0
requirements refer several times to the ``data requirements and
reporting procedures of MOD-013-0,'' which has been identified by the
Commission as a fill-in-the-blank standard, and is pending.
Consequently, they argue that MOD-012-0 cannot be effectively
implemented, and responsible entities should therefore not be subject
to compliance with an incomplete standard.
1170. With respect to the Commission's proposal for adding a new
requirement to this standard, FirstEnergy notes that it is appropriate
for the Commission to require transmission owners to provide the list
of faults or disturbances used in performing dynamics system studies.
However, FirstEnergy cautions that such requirement should accommodate
various electronic formats that are commonly used in industry
simulation tools. FirstEnergy states that compliance with this
provision should not require transmission owners to replace existing
computer and/or software systems, and that the new standard should also
require the regional reliability organizations (or Regional Entities)
to coordinate the lists of faults or disturbances across wide-areas.
1171. MidAmerican agrees that requiring transmission owners to
provide a list of faults or disturbances to neighboring systems would
provide for additional coordination between neighboring utilities, and
therefore, would be an improvement to the standard.
However, MidAmerican warns that a list of faults and disturbances
could be
[[Page 16530]]
used in a ``cook-book'' manner to reach the wrong conclusions.\353\
---------------------------------------------------------------------------
\353\ MidAmerican further discusses that the Commission should
recognize that caution must be taken in assuming that no other
faults and disturbances exist that must be studied under other
conditions. MidAmerican states that like with MOD-010-0, ahead of
time, there is no way to be sure exactly which faults and
disturbances are the worst under given operating conditions. A
single reliability standard cannot contain all the coordination
needed to allow each system operator to fully understand all the
reliability challenges of a neighboring system. Perhaps a better
approach is to continue the joint operational and long-term planning
that is currently being conducted by planning authorities,
reliability coordinators and other regional entities with
transmission planners, transmission owners and others to ensure that
the interconnected network is operated and planned in a coordinated
way.
---------------------------------------------------------------------------
1172. Northern Indiana and MidAmerican note that such a list of
faults and disturbances should be considered a particularly sensitive
form of CEII since it would be a list of events that, when they occur,
cause critical problems on the system. Northern Indiana and MidAmerican
request the Commission to protect sensitive information through the
NERC administrative process discussed in the TOP-005-1 Reliability
Standard.
1173. Xcel raises the same concern it stated about MOD-010-0 that
the proposed modification related to a list of faults and disturbances
is unduly burdensome and would not prove useful to neighboring systems.
Xcel states that no such lists are currently developed or maintained
today, but that the faults and disturbances are reflected in the
computerized models used by transmission providers for both
transmission planning and operations, which are regularly updated as
new facilities are installed. Xcel cautions that the lists, as proposed
by the Commission, would be so long and subject to constant change that
they would not only be burdensome to develop and maintain, but also
unlikely to provide usable information for other transmission owners.
1174. PG&E disagrees with the Commission's proposal related to
lists of faults and disturbances, and repeats its comments from MOD-
010-0 that this new requirement is unnecessary.
1175. Regarding the functional entities to which this standard
applies, APPA notes that the transmission operator and transmission
planner, as functions required to provide information regarding
stability studies, should be added to the list of applicable entities,
while transmission owners should be removed from such list. Under the
NERC Functional Model, transmission owners do not perform any studies
related to MOD-012-0. Rather, a transmission owner merely owns
transmission facilities and maintains them.
1176. California Cogeneration states that this standard raises
concerns about data collection and the cost of compliance, and
therefore a mechanism for determining no material impact and a
provision for exemption is essential for this standard. California
Cogeneration also believes that it is unclear what data is included in
``dynamics system modeling and simulation data,'' and whether
independent generators would have such data.
ii. Commission Determination
1177. The Commission approves MOD-012-0 as mandatory and
enforceable. The Commission directs the ERO to modify MOD-012-0 as
discussed below.
1178. As an initial matter, the Commission disagrees that MOD-012-0
cannot be implemented until MOD-013-1 is modified. We have directed
that data collection and reporting procedures not be interrupted while
MOD-013-1 is being revised, therefore it is possible to implement MOD-
012-0. Failure to provide the data needed for dynamics system modeling
and simulation would halt regional reliability assessment processes and
impede planners from accurately predicting future system conditions,
which would be detrimental to system reliability. We therefore 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 Entities the information related to data gathering, data
maintenance, reliability assessments and other process type functions.
As we will discuss in the next section on MOD-013-1, we require the ERO
to develop a Work Plan and submit a compliance filing that will
facilitate ongoing collection of the dynamics system modeling and
simulation data specified by the deferred MOD-013-1 Reliability
Standard, which is necessary for implementation of MOD-012-0.
1179. Supported by several commenters, we adopt the NOPR proposal
and direct the ERO to modify MOD-012-0 by adding a new requirement to
provide a list of the faults and disturbances used in performing
dynamics system studies for system operation and planning. We believe
that access to such information will enable planners to accurately
study the effects of disturbances occurring in neighboring systems on
their own systems, which will benefit reliability. This requirement
will also make transmission planning data more transparent, consistent
with Order No. 890, which calls for greater openness of the
transmission planning process on a regional basis.
1180. In response to MidAmerican's concern that fault and
disturbance information could be used as a ``cook-book,'' our
expectation is that utility planners who use this data have sufficient
experience to use it and interpret the results correctly. We expect
that most utility planners are already familiar with their neighbors'
system topologies, and will be capable of identifying facilities on
fault and disturbance lists.
1181. We agree with FirstEnergy's concerns regarding the importance
of using existing data collection systems so as to not impose any
additional costs on entities. They may file the fault and disturbance
information in the electronic format in which they were created, along
with any necessary decoding instructions. Compliance with this
provision should not require transmission planners to replace existing
computer and/or software systems. Therefore, we disagree with PG&E and
Xcel that this standard modification will be unduly burdensome.
1182. Consistent with California Cogeneration, Northern Indiana and
MidAmerican's concerns, we determine that the data that a company
considers confidential, market-sensitive or security-sensitive should
be released in accordance with the CEII process or subject to
confidentiality agreements. We direct the ERO to address
confidentiality issues and modify the standard as necessary through its
Reliability Standards development process.
1183. We disagree with commenters that generators or small entities
that do not have a material impact on grid reliability should be
automatically exempt from providing the data required by this
Reliability Standard. The Commission believes that all entities that
are required to register under the registration process that we have
approved must provide data requested by the ERO or the Regional Entity.
1184. We agree with APPA that the functional entity responsible for
providing the fault and disturbance list should be the transmission
planner, instead of the transmission owner, as proposed in the NOPR. We
also agree with APPA that the transmission operator should be added to
the list of applicable entities in the Reliability Standards
development process. Therefore, we direct the ERO to modify
[[Page 16531]]
MOD-012-0 to require the transmission planner to provide fault and
disturbance lists.
1185. We adopt our NOPR proposal that planning authorities should
be included in this 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. We
therefore direct the ERO to add the planning authority to the list of
applicable entities.
1186. Accordingly, the Commission approves MOD-012-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification to MOD-012-0 through the Reliability Standards
development process that: (1) Adds a new requirement for transmission
planners to provide the list of faults and disturbances they use in
performing dynamic stability analysis in the electronic format in which
they were created, along with any necessary decoding instructions and
(2) expands the applicability section to include transmission
operators, planning authorities and transmission planners. We expect
the ERO to address confidentiality issues and modify the Reliability
Standard as necessary through the Reliability Standards development
process.
o. Maintenance and Distribution of Dynamics Data Requirements and
Reporting Procedures (MOD-013-1)
1187. MOD-013-1 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 and response of each Interconnection. 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 to NERC and other specified entities upon request.
1188. In the NOPR, the Commission identified MOD-013-1 as a fill-
in-the-blank standard that requires each regional reliability
organization within an Interconnection to develop comprehensive
dynamics data requirements and reporting procedures needed to model and
analyze the dynamic behavior and response for each of the three NERC
Interconnections. The NOPR stated that because the regional
methodologies had not been submitted, the Commission would not propose
to approve or remand MOD-013-1 until the ERO submits additional
information. In addition, in the NOPR we agreed that the Reliability
Standard should apply to the planning authority.
1189. In the NOPR, the Commission expressed a concern regarding the
1990 cut-off date,\354\ and shared PG&E's concern that the difficulty
in obtaining unit-specific data is not limited to the age, but may also
be due to other factors such as unit configuration. The Commission
requested comment whether it is reasonable to permit entities to
estimate dynamics data if they are unable to obtain unit specific data
for any reason. The Commission believes that to achieve the goal of
this Reliability Standard of having the ability to accurately model and
analyze the dynamic behavior and response of each Interconnection, it
is necessary to have accurate data. Inaccurate data can lead to
unrealistic simulations and inappropriate actions by responsible
entities which may jeopardize the reliability of the Bulk-Power System.
---------------------------------------------------------------------------
\354\ Requirement R1.1.1 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.
---------------------------------------------------------------------------
i. Comments
1190. APPA agrees with the Commission that MOD-013-1 is a fill-in-
the-blank standard, is not sufficient as currently drafted, and should
not be approved as a mandatory Reliability Standard until NERC and the
regional reliability organizations/Regional Entities develop the
necessary regional methodologies and the Commission approves them.
1191. In response to the Commission's request for comments on
whether it is reasonable to permit entities to estimate dynamics data
if they are unable to obtain unit specific data for any reason, many
commenters responded that it is reasonable to allow estimation of
dynamics data for older units where data is not available.\355\ The
Small Entities Forum expects that the Reliability Standard ultimately
will include requirements that such estimates be based on sound
engineering principles and be subject to technical review and approval
of any estimates at the regional level.
---------------------------------------------------------------------------
\355\ EEI, LPPC, MidAmerican, Small Entities Forum and TVA.
---------------------------------------------------------------------------
1192. MidAmerican explains that there may be safety or system
conditions and/or the loss of records that do not permit gathering
unit-specific information, and that in such cases, computations and
engineering reports of estimated capability should be sufficient.
MidAmerican also requests that if there is a farm of similar generation
units (such as wind turbines) or synchronous condensers located in the
same general area, providing unit-specific information for a number of
identical units is not necessary. Instead, MidAmerican proposes that
information about a sample of the identical units (such as two) should
be sufficient to provide enough unit-specific information to be
representative of the farm. MidAmerican also notes that if units are
located in a part of the system that does not typically demonstrate
instability, the value of unit-specific data is reduced, and that there
are a number of such circumstances in which provision of unit-specific
data should not be required.
1193. International Transmission, stating that the age of the unit
alone may not be the only reason why unit-specific data might be
unavailable, cautions that there should be a requirement in every case
that unit data actually be sought for all generating units before
estimates of dynamics data are used. International Transmission
believes that achieving the most accurate possible picture of the
dynamic behavior of the Interconnection requires the use of actual
data, and that, at a minimum, entities should be required to document
the steps taken to obtain unit-specific data.
1194. APPA, however, expresses its concern regarding the
difficulties in obtaining accurate unit-specific data to model dynamic
behavior. APPA recommends to NERC that the regional reliability
organizations/Regional Entities and the reliability coordinators review
this type of data on a case-by-case basis to test it for accuracy and
to determine whether estimated data will produce outputs from the
models within acceptable limits. International Transmission confirms
that testing is easily accomplished, and provides up-to-date dynamics
data reflective of the natural degradation of generating units over
their lifetimes. However, International Transmission says that this
effort could be tied to the Generator Model Validation Reliability
Standards (MOD-024-1 and MOD-025-1).
1195. TANC agrees with the Commission that the standard requirement
is arbitrary in imposing the
[[Page 16532]]
1990 cut-off with regard to modeling dynamic behavior. TANC believes
that this requirement 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. TANC notes that difficulty in
obtaining unit specific data is not limited to the age of the unit but
also unit configuration. TANC therefore recommends that the 1990 cut-
off be removed from the proposed Reliability Standard because there is
no justifiable basis for the arbitrary cut-off and that the Reliability
Standard be revised to allow the generally-accepted use of estimated or
typical manufacturer data where unit-specific data is impractical to
obtain. TVA agrees that the 1990 cut-off date is unnecessary.
1196. In contrast to those who support rejecting the 1990 cut-off
requirement, FirstEnergy states that unit-specific data should be
required for all units installed after 1990. EEI confirms that unit-
specific information should be available for most units placed in
service since 1990.
ii. Commission Determination
1197. The Commission will not approve or remand MOD-013-1 until the
ERO submits additional information. The Commission directs the ERO to
modify MOD-013-1 through the Reliability Standards development process
as discussed below.
1198. We agree with many commenters and direct the ERO to modify
the Reliability Standard to permit entities to estimate dynamics data
if they are unable to obtain unit-specific data for any reason, not
just for units constructed prior to 1990. Achieving the most accurate
possible picture of the dynamic behavior of the Interconnection
requires the use of actual data. We disagree with FirstEnergy and EEI
and reject the 1990 cut-off date, because the age of the unit alone may
not be the only reason why unit-specific data is unavailable. We agree
with the Small Entities Forum that the Reliability Standard should
include Requirements that such estimates be based on sound engineering
principles and be subject to technical review and approval of any
estimates at the regional level. That said, the Commission directs that
this Reliability Standard be modified to require that the results of
these dynamics models be compared with actual disturbance data to
verify the accuracy of the models.
1199. With respect to small units installed in wind farms, we agree
with MidAmerican that data for one unit to represent all identical
units at wind farms is acceptable. The Commission understands that this
is the current approach with any generator that is manufactured in
quantity such as multiple generators used in combined cycle plants.
1200. We adopt our NOPR proposal and direct the ERO to expand the
applicability section in this Reliability Standard to include planning
authorities because they are the entities 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.
1201. Accordingly, the Commission neither accepts nor remands MOD-
013-1 until the ERO submits additional information. Because the
regional procedures have not been submitted to the Commission, it is
not possible to determine at this time whether MOD-013-1 satisfies the
statutory requirement that a proposed Reliability Standard be ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' In the interim, compliance with MOD-013-1 should
continue on a voluntary basis, and the Commission considers compliance
with the Reliability Standard to be a matter of good utility practice.
Although the Commission does not approve or remand MOD-013-1, we direct
the ERO to modify it through the Reliability Standards development
process to: (1) Permit entities to estimate dynamics data if they are
unable to obtain unit specific data for any reason; (2) require
verification of the dynamic models with actual disturbance data and (3)
expand the applicability section to include the planning authority,
transmission operator and transmission planner. As discussed above in
MOD-012-0, we direct the ERO to develop a Work Plan that will
facilitate ongoing collection of the dynamics system modeling and
simulation data specified in MOD-013-1, and submit a compliance filing
containing this Work Plan to the Commission.
p. Development of Steady-State System Models (MOD-014-0)
1202. MOD-014-0 requires the regional reliability organizations
within each Interconnection to coordinate and jointly develop and
maintain a library of solved Interconnection-specific steady-state
models. These models are to include near- and long-term planning
horizons representing system conditions for various demand levels. The
models are to be updated annually.
1203. In the NOPR, the Commission identified MOD-014-0 as a fill-
in-the-blank standard that requires the regional reliability
organizations within an Interconnection to develop, coordinate and
maintain a library of solved Interconnection-specific steady-state
models. The NOPR stated that because the regional procedures had not
been submitted, the Commission would not propose to approve or remand
MOD-014-0 until the ERO submits the additional information. In
addition, in the NOPR the Commission stated its belief that the
Reliability Standard should be modified to include a requirement to
verify that steady-state models are accurate.
1204. In the NOPR, the Commission expressed concern about creating
a duplicate effort if both the transmission owner and the regional
reliability organization separately develop the steady-state base cases
required for the FERC Form 715 filing and for MOD-014-0. The NOPR
suggested that the Reliability Standard contain a requirement
specifying the time period and planning years be identical to those
found in FERC Form 715.\356\ Further, the Commission requested comments
on any incompatibility between requirements under FERC Form 715 and
MOD-014-0.
---------------------------------------------------------------------------
\356\ FERC Form 715 is available at http://www.ferc.gov/docs-filing/eforms.asp#715
.
---------------------------------------------------------------------------
i. Comments
1205. APPA agrees with the Commission that MOD-014-0, a fill-in-
the-blank standard, is not sufficient as currently drafted, and should
not be approved as a mandatory Reliability Standard until NERC and the
regional reliability organizations/Regional Entities develop the
necessary regional methodologies and the Commission approves them.
1206. NRC suggests that a periodic verification against field data
needs to be included in this Reliability Standard.
1207. Regarding the Commission's request for comments on any
incompatibility between requirements under FERC Form 715 and MOD-014-0,
International Transmission states that the language in MOD-014-0 would
allow the regional reliability organization and the transmission owner
to develop separate base cases. International Transmission notes that
its experience with current practice suggests, however, that this is
not a significant concern. Transmission owners now develop the
information for inclusion in a regional base case, and the regional
base case is rolled up into a FERC Form 715 filing by a regional
entity. International Transmission expects that this process would
continue in the future.
[[Page 16533]]
1208. MISO believes that FERC should revisit the need for
transmission owners to have base case information available for
replication. MISO states that the current Interconnection trend is for
transmission owners to work together more closely in developing large
assessments based on a large model, and that these large assessments
are better guides to the overall capability of the transmission grid to
move power. MISO believes that these assessments should be filed as
part of FERC Form 715.
1209. Although Northern Indiana does not see any duplication or
incompatibility with FERC Form 715, Northern Indiana is concerned that
the proposed Reliability Standard envisions the use of steady-state
models and benchmarking for long-term planning. Northern Indiana
believes that benchmarking of planning models should be directed
towards validation of line constraints and general comparison of
modeled to actual load levels. Northern Indiana suggests that this
could be accomplished through validation processes that would first
evaluate the data used to model the transformers and the lines and
determine that such data is correct, and then compare the loads in
total against the actual loads, followed by an examination of
individual load points on a system.
ii. Commission Determination
1210. The Commission will not approve or remand MOD-014-0 until the
ERO submits additional information. Because the regional procedures
have not been submitted to the Commission, it is not possible to
determine at this time whether MOD-014-0 satisfies the statutory
requirement that a proposed Reliability Standard be ``just, reasonable,
not unduly discriminatory or preferential, and in the public
interest.'' The Commission directs the ERO to modify MOD-014-0 as
discussed below.
1211. We maintain our position set forth in the NOPR that analysis
of the Interconnection system behavior requires the use of accurate
steady-state models. Therefore, we direct the ERO to modify the
Reliability Standard to include a requirement that the models be
validated against actual system responses. We understand that NERC is
incorporating recommendations from the Blackout Report \357\ and
developing models for the Eastern Interconnection.
---------------------------------------------------------------------------
\357\ Recommendation Number 24 of the Blackout Report at 160.
---------------------------------------------------------------------------
1212. Further, the maximum discrepancy between the model results
and the actual system response should be specified in the Reliability
Standard. The Commission believes that the maximum discrepancy between
the actual system performance and the model should be small enough that
decisions made by planning entities based on output from the model
would be consistent with the decisions of operating entities based on
actual system response. We direct the ERO to modify MOD-014-0 through
the Reliability Standards development process to require that actual
system events be simulated and if the model output is not within the
accuracy required, the model shall be modified to achieve the necessary
accuracy.
1213. We believe that steady-state model validation should not be
interrupted while MOD-014-0 is being modified. The lack of accurate
models needed for the simulations would halt regional reliability
assessment processes and hinder planners from accurately predicting
future system conditions, which would be detrimental to system
reliability. We therefore direct the ERO to use its authority pursuant
to Sec. 39.2(d) of our regulations to require users, owners and
operators to provide the validated models to regional reliability
organizations. We direct the ERO to develop a Work Plan that will
facilitate ongoing validation of steady-state models and submit a
compliance filing containing the Work Plan with the Commission.
1214. Consistent with many commenters' responses, we find changes
to FERC Form 715 are not necessary at this time, because there is no
conflict between data gathering and model construction with the FERC
Form 715 process.
1215. The Commission neither accepts nor remands MOD-014-0. Because
the regional procedures have not been submitted to the Commission, it
is not possible to determine at this time whether MOD-014-0 satisfies
the statutory requirement that a proposed Reliability Standard be
``just, reasonable, not unduly discriminatory or preferential, and in
the public interest.'' In the interim, compliance with MOD-014-0 should
continue on a voluntary basis, and the Commission considers compliance
with the Reliability Standard to be a matter of good utility practice.
We direct the ERO to: (1) modify the Reliability Standard through the
Reliability Standards development process to require actual system
events be simulated and model output validated against actual system
responses and (2) develop a Work Plan and submit a compliance filing
that will enable validation of the steady-state models while MOD-014-0
is being modified.
q. Development of Dynamics System Models (MOD-015-0)
1216. MOD-015-0 requires the regional reliability organizations
within each Interconnection to coordinate and jointly develop and
maintain a library of initialized (with no faults and disturbances)
Interconnection-specific dynamics system models. These models represent
near-term years and the years chosen from the longer-term planning
horizon.
1217. In the NOPR, the Commission identified MOD-015-0 as a fill-
in-the-blank standard that requires the regional reliability
organizations within an Interconnection to develop, coordinate and
maintain a library of initialized Interconnection-specific dynamics
system models. The NOPR stated that because the regional procedures had
not been submitted, the Commission would not propose to approve or
remand MOD-015-0 until the ERO submits the additional information. In
addition, the Commission stated that MOD-015-0 should include a
requirement to verify accuracy of dynamics system models.
i. Comments
1218. APPA agrees that MOD-015-0 is a fill-in-the-blank standard,
is not sufficient as currently drafted and should not be approved as a
mandatory reliability standard until NERC and the regional reliability
organizations/Regional Entities develop the necessary regional
methodologies and the Commission approves them.
1219. EEI agrees with the Commission's proposal that a new
requirement for verification of the accuracy of dynamics system models
should be a part of this Reliability Standard. In addition, EEI states
that the validation of models is a valid concern, but that any
requirement in this area should be carefully considered, and that any
requirement should be related to using the models to replicate events
that occur on the system instead of developing separate testing
procedures to verify the models. EEI believes that it would not be
reasonable to subject generation units to artificial disturbances to
validate the models. NRC recommends periodic verification against field
data. APPA notes that if NERC modifies MOD-015-0 as APPA anticipates, a
requirement to verify the accuracy of the dynamics system model would
be included and the Regional Entity would be the compliance monitor.
[[Page 16534]]
ii. Commission Determination
1220. The Commission will not approve or remand MOD-015-0 until the
ERO submits additional information. Because the regional procedures
have not been submitted to the Commission, it is not possible to
determine at this time whether MOD-015-0 satisfies the statutory
requirement that a proposed Reliability Standard be ``just, reasonable,
not unduly discriminatory or preferential, and in the public
interest.'' The Commission directs the ERO to modify MOD-015-0 through
the Reliability Standards development process as discussed below.
1221. We maintain our position set forth in the NOPR that the
analysis of Interconnection system behavior requires the use of
accurate dynamics system models. Therefore, we direct the ERO to modify
the Reliability Standard to include a requirement that the models be
validated against actual system responses. We agree with EEI and NRC
and confirm our position that a requirement to verify that dynamics
system models are accurate should be a part of this Reliability
Standard. We agree with EEI that this new requirement should be related
to using the models to replicate events that occur on the system
instead of developing separate testing procedures to verify the models.
We direct the ERO to modify the standard to require actual system
events be simulated and dynamics system model output be validated
against actual system responses.
1222. We believe that dynamics system model validation should not
be interrupted while MOD-015-0 is in the modification process. The lack
of accurate models needed for the simulations would halt regional
reliability assessment processes and hinder planners from accurately
predicting future system conditions, which would be detrimental to
system reliability. We therefore 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 Entity the validated dynamics
system models while MOD-015-0 is being modified. We require the ERO to
develop a Work Plan that will enable continual validation of dynamics
system models and submit a compliance filing with the Commission.
1223. The Commission neither accepts nor remands MOD-015-0 until
the ERO submits additional information. Because the regional procedures
have not been submitted to the Commission, it is not possible to
determine at this time whether MOD-015-0 satisfies the statutory
requirement that a proposed Reliability Standard be ``just, reasonable,
not unduly discriminatory or preferential, and in the public
interest.'' In the interim, compliance with MOD-015-0 should continue
on a voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice. We direct
the ERO to: (1) Modify the Reliability Standard through the Reliability
Standards development process to require verification of the accuracy
of dynamics system models and (2) develop a Work Plan and submit a
compliance filing that will facilitate ongoing verification of the
accuracy of dynamics system models while MOD-015-0 is being modified.
r. Documentation of Data Reporting Requirements for Actual and Forecast
Demands, Net Energy for Load and Controllable Demand-Side Management
(MOD-016-1)
1224. The purpose of MOD-016-1 is to ensure that past and
forecasted demand data is available for validation of past events and
future system assessments. MOD-016-1 requires the planning authority
and the regional reliability organization to have documentation
identifying the scope and details of the actual and forecast demand and
load data, and controllable DSM data to be reported for system modeling
and reliability analysis.
1225. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-016-1 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-016-
1 that expands the applicability section to include the transmission
planner.
i. Comments
1226. APPA agrees that MOD-016-1 is sufficient for approval as a
mandatory and enforceable reliability standard.
1227. In contrast, ISO/RTO Council and ISO-NE do not support
adoption of this standard because it is contingent on standards that
are pending approval by the Commission based on their characterization
as applying only to regional reliability organizations, or because they
have been categorized as fill-in-the-blank standards.\358\ ISO/RTO
Council and ISO-NE agree that as a result, MOD-016-1 cannot be
effectively implemented.
---------------------------------------------------------------------------
\358\ TPL-005-0, TPL-006-0, MOD-011-0, MOD-013-0, MOD-014-0 and
MOD-015-0.
---------------------------------------------------------------------------
1228. APPA and FirstEnergy agree with the Commission's proposal to
direct NERC to add the transmission planner function to the
applicability section of the standard, although they argue that NERC,
as the standards-setting entity, should make the decision.
1229. TAPS does not oppose the proposed applicability of MOD-016-1,
but opposes regional interpretations that apply the standard more
broadly. TAPS criticizes SERC's supplement to MOD-016-1 that makes the
standard applicable to LSEs, even though LSEs do not have the ability
to identify the scope and details of the data required to be reported
for system modeling and reliability analyses. TAPS contends that there
are no physical differences that make SERC LSEs more capable in this
regard than LSEs in other regions. TAPS recommends that the Commission
clarify that it expects standards to be applied in a consistent and
uniform manner as written, and will look closely at regional variations
not justified by physical differences.
1230. In contrast to APPA, FirstEnergy and TAPS, EEI believes that
the standard assigns appropriate responsibility, and that the
transmission planner should not be added to the applicability section
of this standard. According to EEI, the transmission planner has no
specific responsibilities for ensuring data integrity in day-to-day
practice. EEI understands that data integrity falls within the daily
responsibilities of data management functions, such as metering. EEI
states that the NERC Functional Model does not describe technical
functions at this level of detail. EEI notes, as it also notes in its
comments on the TPL standards, that load-related DSM data of the type
and specificity stated in the NOPR, such as load control of customer-
owned appliances, is related to distribution system and operations
planning, and not to transmission system planning.
ii. Commission Determination
1231. The Commission approves MOD-016-1 as mandatory and
enforceable. In addition, the Commission directs the ERO to modify MOD-
016-1 as discussed below.
1232. As an initial matter, we disagree that MOD-016-1 cannot be
implemented until other unapproved standards are modified. As
previously stated, we are requiring the ERO to provide a Work Plan and
compliance filing regarding collection of information specified under
standards that are deferred, and believe there should be no
difficulties complying with this Reliability Standard. We reiterate
that continual collection of data is necessary to maintain system
reliability, and approval of MOD-016-1 will help to achieve this
objective.
1233. Supported by many commenters, the Commission directs
[[Page 16535]]
the ERO to modify MOD-016-1 and expand the applicability section to
include the transmission planner, on the basis that under the NERC
Functional Model the transmission planner is responsible for collecting
system modeling data, including actual and forecast load, to evaluate
transmission expansion plans. We disagree with EEI that this
Reliability Standard should not be applied to the transmission planner
because load-related data for controllable DSM is not only needed for
distribution and transmission operations, but is also necessary for the
transmission planner to take controllable DSM into account in planning
the transmission system. Requirement R1.1 relates to data submittal,
and requires data to be consistent with that supplied for the TPL-005
and TPL-006 standards, which clearly apply to transmission planners. We
approve the ERO's definition in the glossary of DSM as ``all activities
or programs undertaken by a Load-Serving Entity or its customers to
influence the amount or timing of electricity they use.'' Only
activities or programs that meet the ERO definition, with the
modification directed below, may be treated as DSM for purposes of the
Reliability Standards. Recognizing the potential role that industrial
customers who do not take service through an LSE and load aggregators,
for example, may play in meeting the Reliability Standards, we direct
the ERO to modify the definition of DSM. Specifically, we direct the
ERO to add to its definition of DSM ``any other entities'' that
undertake activities or programs to influence the amount or timing of
electricity they use without violating other Reliability Standard
Requirement.
1234. In response to TAPS's criticism of SERC's desire to expand
its regional standards relative to actual and forecast load to include
LSEs, we clarify that we can only act on the standards before us. We do
not make a decision on SERC's standards in this rule. We therefore
recommend that TAPS raise this issue in the Reliability Standards
development process.
1235. The Commission approves Reliability Standard MOD-016-1 as
mandatory and enforceable and directs the ERO to develop a modification
to MOD-016-0 through the Reliability Standards development process to
include the transmission planner in the applicability section.
s. Aggregated Actual and Forecast Demands and Net Energy for Load (MOD-
017-0)
1236. The purpose of MOD-017-0 is to ensure that past and
forecasted demand data is available for past event validation and
future system assessment. MOD-017-0 requires LSEs, planning authorities
and resource planners to annually provide aggregated information on:
(1) Integrated hourly demands; (2) actual monthly and annual peak
demand (MW) and net load energy (GWh) for the prior year; (3) monthly
peak demand forecasts and net load energy for the next two years and
(4) annual peak demand forecasts (summer and winter) and annual net
load energy for at least five and up to ten years into the future.
1237. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-017-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-017-
0 that includes new requirements for: (1) Reporting of temperature and
humidity along with peak loads and (2) reporting of the accuracy, error
and bias of load forecasts compared to actual loads while taking
temperature and humidity variations into account.
i. Comments
1238. APPA agrees that the Commission should approve MOD-017-0 as
mandatory and enforceable.
1239. In contrast to APPA, ISO-NE does not support approval of this
standard because MOD-017-0 depends on MOD-016-0, which further depends
on various unapproved standards. ISO-NE believes that this makes MOD-
017-0 dependent on unapproved standards, and that consequently, MOD-
017-0 cannot be effectively implemented. Similarly, ISO/RTO Council
states that if the Commission does not approve MOD-016-0, then MOD-017-
0 will refer to an unapproved standard.
1240. Although MidAmerican does not oppose the Commission's
proposal regarding reporting of temperature and humidity along with
peak loads, it finds it of only limited value. MidAmerican notes that
there are typically other explanatory variables, such as economic
variables, that are needed to understand the relationship between
system load and temperature and humidity. In addition, the relationship
and the importance of temperatures are different for every utility,
which limits the effectiveness of standardization. FirstEnergy suggests
that NERC should allow for a transition period for entities that
currently do not track temperature and humidity along with peak load.
1241. Xcel states that in many areas of the country, humidity is
not a weather-indicator for peak load. Xcel therefore suggests that
instead of including a reporting requirement for humidity, the standard
be revised to include a more generic term, such as ``peak producing
weather conditions.'' Alcoa requests that the Commission clarify that
these requirements would only apply to load that varies with
temperature and humidity.\359\
---------------------------------------------------------------------------
\359\ Alcoa states that because its smelting load (the vast
majority of its load) does not vary in accordance with temperature
and humidity, comparing Alcoa's load forecasts to actual loads
taking this information into account would be burdensome without
being useful.
---------------------------------------------------------------------------
1242. Regarding the Commission's proposal for reporting of the
accuracy, error and bias of load forecasts compared to actual loads
while taking temperature and humidity variations into account, APPA
disagrees that the Commission should direct NERC to modify MOD-017-0 to
include these requirements. APPA argues that requiring the type and
granularity of forecast information and data the Commission proposes
would not necessarily increase the reliability of load forecasts. APPA
believes that it should be up to NERC, as the expert standards-setting
entity, to decide whether such information would yield enough useful
data to make it worth mandating.
1243. TAPS is concerned that the NOPR's recommendation for
reporting the accuracy, error and bias of load forecasts compared to
actual loads may be interpreted to mean that measuring compliance is a
function of forecast accuracy. TAPS contends that reliance on
percentage-based deviations as a measurement of compliance is
inappropriate when applied to very small entities because an error that
in absolute terms is too small to affect the Bulk-Power System might be
a significant percentage of the entity's load.
1244. EEI notes that the direction of the NOPR proposal seems to
suggest an expansion of the current reporting processes required under
the Energy Information Administration section 411 process. EEI suggests
that such a proposal should consider whether the section 411 process
itself requires change or provides for an adequate level of reporting,
and the extent to which an explicit NERC process requirement could
distract or confuse industry participants.
1245. FirstEnergy states that the transmission planner should be
added to the list of applicable entities for this standard. FirstEnergy
also states that it may be reasonable to interpret or apply this
Reliability Standard in a manner to permit an affected entity that is a
subsidiary in a utility holding company corporate structure to satisfy
its
[[Page 16536]]
reporting requirements by means of a corporate affiliate. Adopting this
interpretation or application would promote efficiency and decrease
confusion in circumstances where several utility subsidiaries in the
same corporate family are subject to this Reliability Standard.
1246. MISO recommends that the Commission direct NERC to change the
requirement of this standard so that aggregated actual hourly demand
data (at the balancing authority level) are to be provided within 30
calendar days of a request from NERC. MISO believes that load
aggregated at this level should be sufficient for the modeling
activities associated with system reliability. MISO understands that
hourly data is collected by those utilities that have balancing
authority responsibilities, and that these utilities can report
aggregated hourly loads for their responsibility area within 30 days.
MISO notes that some balancing authority utilities provide energy
services to smaller municipal or distribution cooperative utilities
where the metering system records only the peak demand and total energy
supplied over approximately 30 days. MISO cautions that the balancing
authority will usually have hourly data for demand and energy within a
segment of the network, but may have no hourly metering on a specific
customer served by that segment.
ii. Commission Determination
1247. The Commission approves MOD-017-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to modify MOD-
017-0 as discussed below.
1248. As an initial matter, we disagree that MOD-017-0 cannot be
implemented because it is dependent on MOD-016-0, which further depends
on various unapproved standards. As previously stated, we direct the
ERO to provide a Work Plan and compliance filing regarding the
collection of information specified under standards that are deferred,
and believe there should be no difficulty complying with this
Reliability Standard. We reiterate that ongoing collection of data is
necessary to maintain system reliability, and approval of MOD-017-0
will help achieve this goal.
1249. As a general matter, the Commission is required to insure
that the Reliability Standards are sufficient to adequately protect
Bulk-Power System reliability.\360\ One of the main drivers in
achieving Reliable Operation is to accurately predict the firm
transactions and native load that must be served. Understanding the
accuracy, error and bias of the forecast and taking action to minimize
them would improve the Reliability Standards and achieve the goal.
---------------------------------------------------------------------------
\360\ Order No. 672 at P 329.
---------------------------------------------------------------------------
1250. The Commission also directs the ERO to modify the Reliability
Standad to require reporting of temperature and humidity along with
peak load because actual load must be weather normalized for meaningful
comparison with forecasted values.\361\ In response to MidAmerican's
observation that it sees little value in collecting this data, we
believe that collecting it will allow all load data to be weather-
normalized, which will provide greater confidence when comparing data
accuracy, which ultimately will enhance reliability. As a result, we
reject Xcel's proposal that the standard be revised to include only the
generic term ``peak producing weather conditions'' because it is too
generic for a mandatory Reliability Standard.
---------------------------------------------------------------------------
\361\ See Brattle Group Report on PJM Load Forecast Model,
available at http://www.pjm.com/planning/res-adequacy/load-forecast.html
.
---------------------------------------------------------------------------
1251. We also reject Alcoa's proposal that the reporting of
temperature and humidity along with peak loads should apply only to
load that varies with temperature and humidity because it essentially
is a request for an exemption from the requirements of the Reliability
Standard and should therefore be directed to the ERO as part of the
Reliability Standards development process. We agree, however, with APPA
that certain types of load are not sensitive to temperature and
humidity. We therefore find that the ERO should address Alcoa's
concerns in its Reliability Standards development process.
1252. The Commission adopts the NOPR proposal directing the ERO to
modify the Reliability Standard to require reporting of the accuracy,
error and bias of load forecasts compared to actual loads with due
regard to temperature and humidity variations. This requirement will
measure the closeness of the load forecast to the actual value. We
understand that load forecasting is a primary factor in achieving
Reliable Operation. Underestimating load growth can result in
insufficient or inadequate generation and transmission facilities,
causing unreliability in real-time operations. Measuring the accuracy,
error and bias of load forecasts is important information for system
planners to include in their studies, and also improves load forecasts
themselves.
1253. The Commission agrees with APPA that accuracy, error and bias
of load forecasts alone will not increase the reliability of load
forecasts, and, as a result, will not affect system reliability.
Understanding of the differences without action based on that
understanding would not change anything. Therefore, we direct the ERO
to add a Requirement that addresses correcting forecasts based on prior
inaccuracies, errors and bias.
1254. Regarding TAPS's concern that accuracy of reporting may be
used as a compliance Measure, we clarify that the compliance Measures
for this Reliability Standard do not measure accuracy as a compliance
Measure. Any change in the Measures would be arrived at in the
Reliability Standards development process.
1255. The Commission acknowledges EEI's concern that a requirement
for additional information may impose an expansion of existing Energy
Information Administration section 411 reporting requirements.\362\ We
believe, however, that the ERO can ensure that the additional reporting
of temperature and humidity along with peak loads does not conflict
with or jeopardize the Energy Information Administration section 411
reporting process.
---------------------------------------------------------------------------
\362\ Form EIA-411, ``Coordinated Bulk Power Supply Program
Report'' collects information about regional electric supply and
demand projections for a five-year advance period as well as
information on the transmission system and supporting facilities.
See http://www.eia.doe.gov/cneaf/electricity/page/forms.html.
---------------------------------------------------------------------------
1256. We agree with FirstEnergy that transmission planners should
be added as reporting entities, and direct the ERO to modify the
standard accordingly. We agree that in the NERC Functional Model, the
transmission planner is responsible for collecting system modeling data
including actual and forecast demands to evaluate transmission
expansion plans.
1257. The Commission disagrees in general with MISO's
recommendation to allow some exceptions to the requirement to provide
hourly demand data. However, the metering for some customer classes may
not be designed to provide certain types of data. The Commission
therefore directs the ERO to consider MISO's concerns in the
Reliability Standards development process.
1258. The Commission approves Reliability Standard MOD-017-0 as
mandatory and enforceable. In addition, the Commission directs the ERO
to develop a modification to MOD-017-0 through the Reliability
Standards development process that includes requirements for: (1)
Reporting of temperature and humidity along with the peak loads; (2)
reporting of accuracy,
[[Page 16537]]
error and bias of load forecasts compared to actual loads taking
temperature and humidity variations into account; (3) addressing
methods to correct forecasts to minimize prior inaccuracies, errors and
bias and (4) including the transmission planner in the applicability
section.
t. Treatment of Nonmember Demand Data and Uncertainties in the
Forecasts of Demand and Energy for Load (MOD-018-0)
1259. The purpose of MOD-018-0 is to ensure that past and
forecasted demand data are available for past event validation and
future system assessment. MOD-018-0 requires LSEs, planning
authorities, transmission planners and resource planners to submit load
data reports that: (1) Indicate whether the demand data includes the
regional reliability organization's non-members' demands and (2)
addresses how assumptions, methods and uncertainties are treated.
1260. In the NOPR, the Commission proposed to approve MOD-018-0 as
mandatory and enforceable.
i. Comments
1261. APPA agrees that MOD-018-0 is sufficient for approval as a
mandatory and enforceable reliability standard.
1262. In contrast to APPA, ISO/RTO Council and ISO-NE view MOD-018-
0 as dependent upon fill-in-the-blank NERC standards, and as such,
argue that the Commission should refrain from approving the Reliability
Standard at this time. ISO-NE states that approval of this standard
would create dependency of MOD-018-0 on other unapproved standards.
Consequently, ISO-NE contends that MOD-018-0 cannot be effectively
implemented.
1263. TAPS reiterates a similar concern it expressed with regard to
MOD-017-0. TAPS notes that uncertainty in a small entity's forecast is
insignificant. TAPS recommends that load forecast uncertainty should be
addressed at an aggregate level on a regional basis (as is often done
in the establishment of reserve obligations).
ii. Commission Determination
1264. The Commission approves MOD-018-0 as mandatory and
enforceable.
1265. As an initial matter, we disagree that MOD-018-0 cannot be
implemented because it is dependent on various unapproved standards. As
previously stated, we direct the ERO to provide a Work Plan and
compliance filing regarding the collection of information specified for
standards that are deferred, and believe there should be no
difficulties complying with this Reliability Standard. We reiterate
that ongoing collection of data is necessary to maintain system
reliability, and approval of MOD-018-0 will help to achieve this goal.
1266. Regarding TAPS's concern that small entities should not be
required to comply with MOD-018-0 because their forecasts are not
significant for system reliability purposes, the Commission directs the
ERO to address this matter in the Reliability Standards development
process.
u. Reporting of Interruptible Demands and Direct Control Load
Management (MOD-019-0)
1267. The purpose of MOD-019-0 is to ensure that past and
forecasted demand data is available for past event validation and
future system assessment. The Reliability Standard requires that LSEs,
planning authorities, transmission planners and resource planners
annually provide their forecasts of interruptible demands and direct
control load management to NERC, the regional reliability organization
and other entities as specified in MOD-016-1, Requirement R1. The data
should contain the forecasts for at least five years, and up to ten
years.
1268. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-019-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-019-
0 that includes new requirements for reporting of the accuracy, error
and bias of controllable load \363\ forecasts.
---------------------------------------------------------------------------
\363\ While MOD-019-0 and MOD-020-0 use two separate terms,
interruptible load and direct control load management, the NOPR uses
``controllable load'' to refer to both of them.
---------------------------------------------------------------------------
i. Comments
1269. APPA agrees that MOD-019-0 should be approved as mandatory
and enforceable. However, APPA states that the proper entity to decide
whether the recommended changes to the standards should be made is
NERC, through Reliability Standards development process.
1270. The ISO/RTO Council and ISO-NE note that MOD-019-0 is
dependent, through MOD-016, on various unapproved standards.
Consequently, they contend that MOD-019-0 cannot be effectively
implemented.
1271. APPA proposes that NERC consider modifying MOD-019-0 to
include new requirements for reporting on the accuracy, error and bias
of controllable load forecasts. APPA further believes that NERC should
consider adding requirements that would require resource planners to
analyze differences between actual and forecasted demands for the five
years of actual controllable load required in MOD-019-0 and identify
what corrective actions were taken to improve controllable load
forecasting for the 10-year planning horizon.
1272. EEI and FirstEnergy state that determining the precise
availability and capability of direct load control is a difficult
management and customer relations exercise, and therefore, this
requirement should not be included in the Reliability Standard. EEI
states that, unlike other technical requirements for generation
resources to be tested for various capabilities and limits under
different types of stresses, there are no similar requirements for load
control equipment. Elsewhere in these comments, EEI supports explicit
recognition that load control should be recognized on the same terms as
generation resources for setting reserve requirements. However, EEI
cautions against imposing requirements to verify load control devices
and interruptible loads, because the practical complexities of
conducting such testing and verification, including customer
notification, the need to plan, manage, and coordinate testing with
critical commercial and industrial customer activities, and the need to
conduct such tests at times of peak load, make this an extremely
difficult operational challenge.
1273. International Transmission notes that many load control
applications are not individually metered, which means impact can only
be estimated within a LSE's service territory. International
Transmission believes that accurate reporting may not be feasible.
1274. TAPS raises concern that the Commission's recommendation in
the NOPR may be interpreted to make forecast accuracy a component of
Reliability Standards compliance. TAPS cautions that reliance on
percentage-based deviations as a measurement of compliance is
inappropriate when applied to very small entities because an error that
in absolute terms is too small to affect the Bulk-Power System might be
a significant percentage of the entity's load. The percentage deviation
from a forecasted peak of a small (e.g., 10 MW) entity will almost
always be significantly higher than the percentage deviation of a large
(more than 10,000 MW) entity, but the smaller system's deviation will
have little if any impact on the bulk transmission system. In other
contexts, the Commission has recognized that reliance solely on
[[Page 16538]]
percentage deviations as compliance measures can produce discriminatory
results, and has applied MW minimums to minimize the discrimination
that would otherwise result.
ii. Commission Determination
1275. The Commission approves MOD-019-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to modify MOD-
019-0 as discussed below.
1276. As an initial matter, we disagree that MOD-019-0 cannot be
implemented because it is dependent on MOD-016-0, which further depends
on various unapproved standards. As previously stated, we direct the
ERO to provide a Work Plan and compliance filing regarding the
collection of information specified under related standards that are
deferred, and believe there should be no difficulties complying with
this Reliability Standard. We reiterate that ongoing collection of data
is necessary to maintain system reliability, and approval of MOD-019-0
will help to achieve this goal. We therefore 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 Entity
information related to forecasts of interruptible demands and direct
control load management.
1277. The Commission adopts the NOPR proposal directing the ERO to
modify this standard to require reporting of the accuracy, error and
bias of controllable load forecasts. This requirement will enable
planners to get a more reliable picture of the amount of controllable
load that is actually available, therefore allowing planners to conduct
more accurate system reliability assessments. The Commission finds that
controllable load can be as reliable as other resources, and therefore
should also be subject to the same reporting requirements. Although we
recognize that verifying load control devices and interruptible loads
may be complex, we do not believe that it is overly so. Further, we
believe that the ERO, through its Reliability Standards development
process can develop innovative solutions to the Commission's concern.
We also note that EEI is concerned about such testing at times of peak
load. We clarify that we are not requiring the testing to be conducted
at peak load conditions. Consequently, we reject the proposals of EEI,
FirstEnergy and International Transmission to discard the requirement
for reporting of the accuracy, error and bias of controllable load
forecasts.
1278. We direct the ERO to include APPA's proposal in the
Reliability Standards development process to add a new requirement to
MOD-019-0 that would oblige resource planners to analyze differences
between actual and forecasted demands for the five years of actual
controllable load and identify what corrective actions should be taken
to improve controllable load forecasting for the 10-year planning
horizon.
1279. Regarding TAPS' concern that reporting accuracy could be used
as a compliance Measure, we clarify that compliance Measures for this
Reliability Standard do not include accuracy as a compliance measure.
Any change in this policy would be arrived at in the ERO Reliability
Standards development process.
1280. Accordingly, the Commission approves MOD-019-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification to MOD-019-0 through the Reliability Standards
development process to require: (1) Reporting of the accuracy, error
and bias of controllable load forecasts and (2) analyzing differences
between actual and forecasted demands for the five years of actual
controllable load and identify what corrective actions should be taken
to improve controllable load forecasting for the 10-year planning
horizon.
v. Providing Interruptible Demand and Direct Control Load Management
Data to System Operators and Reliability Coordinators (MOD-020-0)
1281. The purpose of MOD-020-0 is to ensure that past and
forecasted demand data are available for validation of past events and
future system assessment. The Reliability Standard requires that each
LSE, planning authority, transmission planner and resource planner
identify its amount of: (1) Interruptible demand and (2) direct control
load management to transmission operators, balancing authorities and
reliability coordinators upon request.
1282. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-020-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-020-
0 that includes a new requirement concerning the reporting of the
accuracy, error and bias of controllable load forecasts in its
Reliability Standards development process.
i. Comments
1283. APPA supports approval of MOD-020-0 as mandatory and
enforceable, as proposed by the Commission. APPA does not oppose NERC's
consideration of possible changes to MOD-020-0 regarding the reporting
of the accuracy, error and bias of controllable load forecasts.
1284. EEI and FirstEnergy state that for practical reasons,
determining the precise availability and capability of direct load
control is a difficult management and customer relations exercise.
Unlike other technical requirements for generation resources to be
tested for various capabilities and limits under different types of
stresses, there are no similar requirements for load control equipment.
The practical complexities of conducting such testing and verification,
including customer notification, the need to plan, manage and
coordinate testing with critical commercial and industrial customer
activities, and the need to conduct such tests at times of peak load
make this an extremely difficult operational challenge.
1285. LPPC opposes the Commission's proposal for modification to
report the accuracy of load forecasts. LPPC points out that load
reduction forecasts are imprecise by nature, and, consequently, some
utilities do not undertake them. LPPC also notes that interruptible
loads are often on one-year contracts and, in some regions, instances
of entities actually exercising load reduction are rare; in these
areas, system operators often do not separately forecast interruptible
load reductions, and reporting on the accuracy of forecasts on
interruptible load reductions, even if interruptible load forecasts
were done, is of little value. LPPC states that in other areas, such as
New York, interruptible load reductions are more predictable, because
many large loads have signed interruptible load contracts and have a
history of exercising load reductions. LPPC notes that system operators
in areas similar to New York have sufficient data so that forecasting
for interruptible loads is a useful exercise, and as a result, a
requirement to report on the accuracy of forecasts in these regions
would be of some value, but not elsewhere. Consequently, LPPC
recommends that the requirement should be region-specific and should
only apply to entities that separately forecast interruptible loads.
LPPC further notes that energy efficiency programs are often built into
the larger assumptions in the forecast and are not separately
forecasted.
1286. TAPS is concerned that the Commission's recommendation in the
NOPR may be interpreted to make forecast accuracy a component of
Reliability Standards compliance.
[[Page 16539]]
However, it asserts that reliance on percentage-based deviations as a
measurement of compliance is inappropriate when applied to very small
entities because an error that in absolute terms is too small to affect
the Bulk-Power System might be a significant percentage of the entity's
load. The percentage deviation from a forecasted peak of a small (e.g.,
10 MW) entity will almost always be significantly higher than the
percentage deviation of a large (more than 10,000 MW) entity, but the
smaller system's deviation will have little if any impact on the bulk
transmission system. In other contexts, the Commission has recognized
that reliance solely on percentage deviations as a compliance measure
can produce discriminatory results, and has applied MW minimums to
minimize the discrimination that would otherwise result.
ii. Commission Determination
1287. The Commission approves MOD-020-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to modify MOD-
020-0 as discussed below.
1288. We adopt the proposal to direct the addition of a requirement
for reporting of the accuracy, error and bias of controllable load
forecasts because we believe that reporting of this information will
provide applicable entities with advanced knowledge about the exact
amount of available controllable load, which will improve the accuracy
of system reliability assessments. The Commission finds that
controllable load in some cases may be as reliable as other resources
and therefore must also be subject to the same reporting requirements.
We recognize that determining the precise availability and capability
of direct load control is a difficult management and customer relations
exercise, but we do not believe that it will be overly so. Further, we
believe that the ERO, through its Reliability Standards development
process can develop innovative solutions to the Commission's concern.
Regarding LPPC's suggestion that this requirement should be region-
specific and should only apply to entities that separately forecast
interruptible loads, we note that if a region does not forecast
interruptible loads, this Reliability Standard does not apply.
1289. Regarding TAPS' concern that forecast accuracy may be
interpreted as a component of Reliability Standards compliance, we
clarify that compliance Measures for this Reliability Standard do not
measure accuracy as a compliance measure. Any change in this policy
would be arrived at in the ERO Reliability Standards development
process.
1290. The Commission approves Reliability Standard MOD-020-0 as
mandatory and enforceable and directs the ERO to develop a modification
to MOD-020-0 through the Reliability Standards development process to
require reporting of the accuracy, error and bias of controllable load
forecasts.
w. Documentation of the Accounting Methodology for the Effects of
Controllable Demand-Side Management in Demand and Energy Forecasts
(MOD-021-0)
1291. MOD-021-0 requires LSEs, transmission planners and resource
planners to clearly document how each addresses the demand and energy
effects of DSM programs. The standard also requires an applicable
entity to include information detailing how DSM measures are addressed
in the forecasts of its peak demand and annual net energy for load in
the data reporting procedures of MOD-016-0, Requirement R1.
1292. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-021-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-021-
0 that: (1) Includes a requirement standardizing principles on
reporting and validation of DSM program information and (2) modifies
the title and purpose statement to remove the word ``controllable.''
i. Comments
1293. APPA supports the Commission's approval of MOD-021-0 as
mandatory and enforceable.
1294. In contrast, ISO-NE and ISO/RTO Council oppose adoption of
this standard by the Commission. ISO-NE argues that the LSE,
transmission planner and resource planner should each include
information regarding how DSM measures are addressed in the forecasts
of its peak demand and annual net energy for load in the data reporting
procedures of MOD-016-0 R1. Therefore, they contend that, because MOD-
016-0 is dependent on various unapproved Reliability Standards, MOD-
021-0 is also dependent on unapproved Reliability Standards.
Consequently, ISO-NE contends that MOD-021-0 cannot be effectively
implemented.
1295. FirstEnergy and SMA support the Commission's proposal to
require consistent and uniform methods for reporting and validating
demand-side information. SMA notes that this will provide more
consistent and uniform evaluation of demand response data to facilitate
system operator confidence in relying on such resources for various
reliability purposes. In addition, APPA believes that NERC should
consider adding requirements to MOD-021-0 that would provide
information to allow resource planners to analyze the causes of
differences between actual and forecasted demands, and to identify any
corrective actions that should be taken to improve forecasted demand
responses for future forecasts. APPA believes that all of these
proposals should be submitted to NERC as the standards-setting body
with technical expertise, and vetted through its Reliability Standards
development process, rather than being imposed by Commission fiat.
1296. FirstEnergy adds that MOD-019-0, MOD-020-0 and MOD-021-0
should be combined because they all address load forecast inputs, and
that combining these standards will eliminate any inconsistencies and
make compliance easier and more efficient.
ii. Commission Determination
1297. The Commission approves MOD-021-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a
modification to MOD-021-0 through the Reliability Standards development
process as discussed below.
1298. As an initial matter, we disagree that MOD-021-0 cannot be
implemented because it is based on MOD-016-0, and through it on various
unapproved standards, which creates an implementation problem. As
previously stated, we direct the ERO to provide a Work Plan and
compliance filing regarding collection of information specified under
related standards that are deferred, and believe there should be no
difficulty complying with this Reliability Standard. We reiterate that
ongoing collection of data is necessary to maintain system reliability,
and approval of MOD-21-0 will help to achieve this goal. Therefore, we
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 Entity the information required by this Reliability Standard.
1299. We agree with FirstEnergy and SMA that standardization of
principles on reporting and validating DSM program information will
provide consistent and uniform evaluation of demand response to
facilitate system operator confidence in relying on such resources,
which will further increase accuracy of transmission system reliability
assessment and consequently
[[Page 16540]]
enhance overall reliability. We direct the ERO to modify this
Reliability Standard to allow resource planners to analyze the causes
of differences between actual and forecasted demands, and to identify
any corrective actions that should be taken to improve forecasted
demand responses for future forecasts. Therefore, we adopt the NOPR
proposal and direct the ERO to modify MOD-021-0 by adding a requirement
for standardization of principles on reporting and validating DSM
program information.
1300. With respect to FirstEnergy's suggestion to combine MOD-019-
0, MOD-020-0 and MOD-021-0, we understand that the ERO intends to
consolidate Reliability Standards and encourage FirstEnergy to make its
suggestion in the Reliability Standards development process.
1301. The Commission directs the ERO to modify the title and
purpose statement to remove the word ``controllable.'' We note that no
commenter disagrees.
1302. The Commission approves Reliability Standard MOD-021-0 as
mandatory and enforceable. We direct the ERO to develop a modification
to MOD-021-0 through the Reliability Standards development process to
(1) add a Requirement standardizing principles on reporting and
validation of DSM program information; (2) allow resource planners to
analyze the causes of differences between actual and forecasted
demands, and to identify any corrective actions that should be taken to
improve forecasted demand responses for future forecasts and (3) modify
the title and purpose statement to remove the word ``controllable.''
x. Verification of Generator Gross and Net Real Power Capability (MOD-
024-1)
1303. The purpose of MOD-024-1 is to ensure that accurate
information on generation gross and net real power capability is used
for reliability assessments. The Reliability Standard requires the
regional reliability organization to establish and maintain procedures
to address verification of generator gross and net real power
capability. It also requires a generator owner to follow its regional
reliability organization's procedure for verifying and reporting gross
and net real power generating capability.
1304. In the NOPR, the Commission identified MOD-024-1 as a fill-
in-the-blank standard that requires the regional reliability
organization to establish and maintain procedures to address
verification of generator gross and net real power capability. The
Commission stated that because the regional procedures had not been
submitted, it would not propose to approve or remand MOD-024-1 until
the ERO submits the additional information. In addition, the Commission
expressed concern that the Reliability Standard is not sufficiently
clear because it does not define test conditions, e.g., ambient
temperature, river water temperature or methodologies for calculating
de-rating factors for conditions such as higher ambient temperatures
than the test temperature. Further, the NOPR stated that Requirement R2
provides that the ``regional reliability organization shall provide
generator gross and net real power capability verification within 30
calendar days of approval'' and noted that it is not clear what
approval is required and when the 30-day period starts.
i. Comments
1305. APPA agrees that MOD-024-1 is a fill-in-the-blank standard,
is not sufficient as currently drafted, and should not be approved as a
mandatory Reliability Standard until NERC and the regional reliability
organizations/Regional Entities develop the necessary regional
methodologies and the Commission approves them.
1306. APPA also states that the results of field-testing will
enable NERC to refine this Reliability Standard in an appropriate
manner. APPA further believes that NERC should consider modifying this
Reliability Standard to provide requirements for this information on an
Interconnection-wide basis, in the same manner that IRO-006-2 sets the
requirement for transmission loading relief in each Interconnection.
1307. Northern Indiana urges the Commission to reconsider the
proposed changes at this time in favor of continuation of the
currently-effective Reliability Standard. Northern Indiana states that
the NOPR's suggestion that there should be greater specificity and
definition of test conditions could potentially create reliability
issues, rather than protect against them. Northern Indiana explains
that certain types of testing, and their preparation, can be
accomplished more quickly than others, with test duration varying from
several minutes to several days.\364\ The problem is compounded if a
test takes some time to complete, and all neighboring generating owners
were required to comply at the same time. The end result would be a
lack of regulating capability in a region.
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\364\ Northern Indiana states that the longer the duration, the
more stressed the units--and the system--during these testing
intervals. For example, Commission staff recommends the use of
ambient air temperature and river water temperature as triggering
tests to verify generator gross and net real power capability.
However, temperature-driven test triggers would result in several
neighboring systems in the same region undergoing tests at the same
time in order to meet the test criteria. For example, a temperature
trigger of 90 degrees Fahrenheit for a net demonstrated capacity
test could result in all neighboring generating owners taking their
units off of automatic generator control to reach maximum net
demonstrated capacity for the test. By taking units off automatic
generator control, the generating owners' regulating capabilities
are lost.
---------------------------------------------------------------------------
1308. Constellation encourages the Commission and NERC to take
extra care in distinguishing between those requirements in each
Reliability Standard that are core requirements as opposed to
supporting information, explanatory statements or administrative
processes. For example, Constellation points out that in MOD-024-1,
NERC proposes that a verification process be made into a Reliability
Standard with full enforceability. Although Constellation agrees that
the verification process spelled out in this Reliability Standard is
important and should be performed by the industry, the Reliability
Standard, alone, exclusively provides for an administrative process
and, therefore, if not strictly complied with, does not necessarily
foreshadow an immediate, real-time reliability problem on the bulk
electric system. Constellation is concerned that the Levels of Non-
Compliance associated with MOD-024-1 and MOD-025-1 are based on
arbitrary percentages that have little to do with the impact a failure
to perform would have on reliability. Constellation believes that these
problems ultimately will reduce the effectiveness of the Reliability
Standards. Consequently, Constellation requests that the Commission
recognize these concerns and direct NERC to take them into
consideration during the Reliability Standards development process.
ii. Commission Determination
1309. The Commission will not approve or remand MOD-024-1 until the
ERO submits additional information. In order to continue verifying and
reporting gross and net real power generating capability needed for
reliability assessment and future plans, we direct the ERO to develop a
Work Plan and submit a compliance filing.
1310. The Commission remains concerned that the Reliability
Standard is not sufficiently clear because it does not define the test
conditions and methodologies for calculating de-rating
[[Page 16541]]
factors. The Commission does not agree with APPA that NERC should
consider modifying this Reliability Standard to provide requirements
for this information on an Interconnection-wide basis, in the same
manner that IRO-006-3 sets the requirements for transmission loading
relief in each Interconnection. We believe, however, that while the
overall methodology for verification of generator gross and net real
power capability should be the same, test conditions (such as ambient
temperature, river water temperature, etc.) can vary.
1311. In the NOPR, the Commission stated that the Reliability
Standard could be improved by defining test conditions, e.g., ambient
temperature, river water temperature, and methodologies for calculating
de-rating factors for conditions such as higher ambient temperatures
than the test temperature. With the test information and methodologies,
the generator output that can be expected to be available at forecasted
weather conditions can be determined. The Commission agrees with
Northern Indiana that testing all units at the same time is not
feasible. However, the Commission did not propose simultaneous testing.
Rather, we direct the ERO to develop appropriate requirements to
document test conditions and the relationships between test conditions
and generator output so that the amount of power that can be expected
to be delivered from a generator at different conditions, such as peak
summer conditions, can be determined. Similarly, we respond to
Constellation that any modification of the Levels of Non-Compliance in
this Reliability Standard should be reviewed in the ERO Reliability
Standards development process.
1312. We repeat our concern that Requirement R2, which specifies
that the ``regional reliability organization shall provide generator
gross and net real power capability verification within 30 calendar
days of approval,'' is not clear. The requirement lacks a definition of
what approval is required and when the 30-day period starts. Therefore,
we direct the ERO to modify this Reliability Standard by adding
information that will clarify this requirement.
1313. The Commission neither accepts nor remands MOD-024-1 until
the ERO submits additional information. Although the Commission did not
propose any action with regard to MOD-024-1, it addressed above a
number of concerns regarding the Reliability Standard. We therefore
direct the ERO to use its authority pursuant to Sec. 39.2(d) of our
regulations to require users, owners and operators to provide this
information. In the interim, compliance with MOD-024-0 should continue
on a voluntary basis, and the Commission considers compliance with it
to be a matter of good utility practice.
y. Verification of Generator Gross and Net Reactive Power Capability
(MOD-025-1)
1314. MOD-025-1 requires the regional reliability organization to
establish and maintain procedures to address verification of generator
gross and net reactive power capability. The Reliability Standard also
requires the regional reliability organization to provide its generator
gross and net reactive power capability verification and reporting
procedures, and any changes to those procedures, to the generator
owners, generator operators, transmission operators, planning
authorities and transmission planners affected by the procedure within
30 calendar days of approval of the Reliability Standard.
1315. In the NOPR, the Commission identified MOD-025-1 as a fill-
in-the-blank standard that requires the regional reliability
organization to establish and maintain procedures to address
verification of generator gross and net reactive power capability. The
NOPR stated that because the regional procedures had not been
submitted, the Commission would not propose to approve or remand MOD-
025-1 until the ERO submits the additional information. In addition,
the Commission suggested that MOD-025-1 could be clearer by requiring a
minimum reactive power (MVAR) capability throughout a unit's real power
operating range. Further, the NOPR stated that requirement R2 provides
that the ``regional reliability organizations shall provide generator
gross and net real power capability verification within 30 calendar
days of approval'' and noted that it is not clear what approval is
required and when the 30-day period starts.
i. Comments
1316. APPA agrees that the Commission should not approve this
Reliability Standard until NERC and the regional reliability
organizations/Regional Entities develop the necessary regional
methodologies and the Commission approves them.
1317. MidAmerican notes that the Reliability Standard will be
clearer if minimum reactive power capability is required throughout a
unit's real power operating range. However, making this a Requirement
for existing units would be a hardship for units not built with the
Requirement in mind. Therefore, MidAmerican suggests that any such
requirement should allow existing units to be grandfathered in as they
are currently rated so that a new minimum reactive power standard is
only applicable to new generating units or units that are being
significantly upgraded.
1318. Northern Indiana cautions the Commission against the
establishment of a minimum capability, because it could diminish a
unit's ability to contribute to Interconnection reliability, and to
maintain its own stability. Northern Indiana points out that all
generators have reactive capability curves from design manufacturers,
and these curves provide operators with a range that is considered by
the manufacturer to be a safe operating limit. Northern Indiana
contends that the continued use of reactive capability curves is
superior to establishment of an MVAR capability, and that operators
effectively use these curves to maintain unit stability, while also
contributing to the reliability of the Interconnection. Northern
Indiana believes that continued reliance on manufacturer reactive
capability curves is a technically sound means to achieve the
Reliability Standard's stated reliability goal in a manner superior to
the establishment of MVAR capability.
1319. Similarly to Northern Indiana, Wisconsin Electric encourages
the Commission to withdraw this suggested modifications to NERC's
Reliability Standard for several reasons. Wisconsin Electric believes
that a requirement to test and verify the minimum reactive capability
at multiple points over the operating range as part of the additional
minimum MVAR capability requirement would be a significant and
unnecessary burden on utilities. In Wisconsin Electric's experience, a
reactive power test at a single operating point is sufficient and more
practical to achieve.
1320. SoCal Edison recommends that the Commission specifically
state the effective date for compliance with each Reliability Standard
in its Final Rule. SoCal Edison states that the effective date is
critical and gives the example of MOD-025-1, with effective dates
phased in over several years after they are adopted by the NERC board
of trustees, and well after the date the Final Rule will be issued.
ii. Commission Determination
1321. The Commission will not approve or remand MOD-025-1 until the
ERO submits additional information. In order to continue verifying and
reporting gross and net reactive power generating capability needed for
reliability assessment and future plans,
[[Page 16542]]
we direct the ERO to develop a Work Plan as defined in the Common
Issues section.
1322. We disagree with commenters that verifying generator reactive
capability is a particularly difficult issue. The capability of
generators to produce reactive power is essential for real-time
analysis and planning. The Reliability Standard addressing this issue
requires a generator to verify reactive capability only at the unit's
full MW loading. However, other than baseload units, most generating
units rarely operate at full MW loading. It is unclear what reactive
capability is available throughout a unit's real power (MW) operating
range. Therefore, we believe a clearer standard would require a
verification of MVAR capability throughout a unit's real power (MW)
operating range. However, we share concern with several commenters that
such a requirement for all generators may not be necessary. Therefore,
we adjust the proposal in the NOPR and direct the ERO to modify MOD-
025-1 to require verification of reactive power capability at multiple
points over a unit's operating range.
1323. We maintain the concern we expressed in the NOPR that
Requirement R2 provides that the ``regional reliability organization
shall provide generator gross and net reactive power capability
verification within 30 calendar days of approval'' and note that it is
not clear what approval is required and when the 30-day period starts.
We direct the ERO to provide clarification on this requirement.
1324. The Commission neither accepts nor remands MOD-025-1 until
the ERO submits additional information. Although the Commission did not
propose any action with regard to MOD-025-1, it addresses above a
number of concerns regarding the Reliability Standard. We direct the
ERO to develop a Work Plan to verify and report on generator gross and
net reactive power capability while this Reliability Standard is being
modified and to modify this Reliability Standard through the
Reliability Standards development process to: (1) Require verification
of a reactive power capability at multiple points over a unit's
operating range and (2) clarify Requirement R2 with a definition of
what approval is needed and when the 30-day period starts.
9. PER: Personnel Performance, Training and Qualifications
1325. The four proposed Personnel Performance, Training and
Qualifications (PER) Reliability Standards are applicable to
transmission operators, reliability coordinators and balancing
authorities with the intention of ensuring the safe and reliable
operation of the interconnected grid through the retention of suitably
trained and qualified personnel in positions that can impact the
reliable operation of the Bulk-Power System. The PER Reliability
Standards address: (1) Operating personnel responsibility and
authority; (2) operating personnel training; (3) operating personnel
credentials and (4) reliability coordination staffing.
a. Operating Personnel Responsibility and Authority (PER-001-0)
1326. PER-001-0 requires that transmission operator and balancing
authority personnel have the responsibility and authority to direct
actions in real-time. PER-001-0 also requires clear documentation that
operating personnel have the responsibility and authority to implement
real-time action to ensure the stable and reliable operation of the
Bulk-Power System.
1327. In the NOPR, the Commission proposed to approve PER-001-0 as
mandatory and enforceable.
i. Comments
1328. APPA agrees that PER-001-0 is sufficient for approval as a
mandatory and enforceable Reliability Standard.
1329. ISO-NE supports the adoption of this Reliability Standard
provided that the Commission does not mandate that the tasks performed
by local control centers be included in the definition of transmission
operators. It explains that to do so would suggest that the local
control center has independent autonomy in operating the Bulk-Power
System, which conflicts with the ``one set of hands on the wheel''
philosophy supported by Order No. 2000 and the operating agreements
approved by the Commission to establish ISO-NE as New England's RTO.
ii. Commission Determination
1330. The Commission agrees with the ``one set of hands on the
wheel'' philosophy described by ISO-NE as it applies to operations of
the Bulk-Power System and has no intention of deviating from it.
Nothing in the Commission's proposed modifications outlined in the NOPR
in regard to the PER Reliability Standards is intended to conflict with
this philosophy. A generic discussion of the local control centers is
included in the Applicability Issues section and specific implications
to operator training are discussed in PER-002-0.\365\
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\365\ See Applicability Issues: Use of the NERC Functional
Model, supra section II.C.4.
---------------------------------------------------------------------------
1331. Accordingly, the Commission approves PER-001-0 as mandatory
and enforceable. We find that the Reliability Standard is just,
reasonable, not unduly discriminatory or preferential and in the public
interest.
b. Operating Personnel Training (PER-002-0)
1332. PER-002-0 requires that transmission operator and balancing
authority personnel are adequately trained. The Reliability Standard:
(1) Directs each transmission operator and balancing authority to have
a training program for all operating personnel who occupy positions
that either have primary responsibility, directly or indirectly, for
the real-time operation of the Bulk-Power System or who are directly
responsible for complying with the NERC Reliability Standards; (2)
lists criteria that must be met by the training program and (3)
requires that operating personnel receive at least five days of
training in emergency operations each year using realistic simulations.
1333. In the NOPR, the Commission proposed to approve Reliability
Standard PER-002-0 as mandatory and enforceable. In addition, the
Commission proposed to direct that NERC submit a modification to PER-
002-0 that: (1) Identifies the expectations of the training for each
job function; (2) develops training programs tailored to each job
function with consideration of the individual training needs of the
personnel; (3) expands the applicability to include reliability
coordinators, generator operators, and operations planning and
operations support staff with a direct impact on the reliable operation
of the Bulk-Power System; (4) uses the Systematic Approach to Training
(SAT) methodology in its development of new training programs and (5)
includes performance metrics associated with the effectiveness of the
training program. In addition, the Commission requested comments on the
benefits and appropriateness of required ``hands-on'' training using
simulators in dealing with system emergencies.
i. General Issues
(a) Comments
1334. EEI supports the Commission's direction for personnel
training and generally agrees with the Commission's proposal for PER-
002-0. EEI states NERC is developing a new Reliability Standard, PER-
005-0, which could be
[[Page 16543]]
filed with the Commission as early as July 2007. According to EEI, this
new Reliability Standard will respond to the issues raised in the NOPR
regarding PER-002-0. EEI notes that the ERO plans to retire Reliability
Standards PER-002-0 and PER-004-1 when proposed PER-005-0 is adopted.
It recommends that the Commission consider consolidating all training
requirements into a single Reliability Standard to simplify the
Reliability Standards catalog.
1335. Additional comments received have been grouped as follows:
Local control center personnel; applicability to generator operators;
applicability to operations planning and operations support staff;
implications to small systems; training performance metrics; use of SAT
methodology; and use of simulators separately, followed by an overall
conclusion and summary.
(b) Commission Determination
1336. EEI's comments concerning a possible PER-005-0 are beyond the
scope of this proceeding. The Commission will not require the ERO to
consolidate all training requirements into a single Reliability
Standard. We believe that such matters should be left to the discretion
of the ERO through its Reliability Standards development process.
ii. Local Control Center Personnel
1337. In the NOPR, the Commission noted that decisionmaking and
implementation may be performed by separate groups in an ISO or RTO
context, as well as other organizations that pool resources.\366\ The
Commission proposed that all control centers and organizations that are
necessary for the actual implementation of the decision or are needed
for operation and maintenance made by the ISO, RTO or pooled resource
organization should be part of the transmission or generator operator
function. Although the NOPR discussed this matter in the context of the
Communication (COM) Reliability Standards, the NOPR indicated that the
proposal would apply in the training and certification context, as
well.\367\
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\366\ NOPR at P 236-37.
\367\ Id. at P 237, 779.
---------------------------------------------------------------------------
(a) Comments
1338. EEI states that the term ``operating personnel'' as used in
the PER group of Reliability Standards needs clarification because it
may be interpreted to mean any person with a capability to take a
unilateral action that can have a potentially significant effect on the
Bulk-Power System. EEI states that the term is open to broad
interpretation in actual practice, subject to various contracts,
operating agreements and ISO/RTO procedures. It states, for example, a
local control center operator may take instructions from and act on
those instructions, whereas the ``transmission operator'' under the
Functional Model may be viewed as a more centralized authority such as
a larger regional system operator. EEI contends that some define local
control center as a transmission operator, while others disagree.
1339. ISO-NE states the scope of PER-002-0 need not be expanded
because local control center personnel in its footprint implement tasks
delegated to them by ISO-NE for operation of designated transmission
facilities. NPCC argues that expanding PER-002-0 beyond the entities
identified under the NERC Functional Model (i.e., transmission
operators, reliability coordinators and balancing authorities) will
require substantial cost and time but add little value. It states that
there are no certification exams for any entities other than
transmission operators, reliability coordinators and balancing
authorities and to develop and implement such exams and to have the
additional personnel certified would take several years. It also states
that these personnel already function under the authority of NERC-
certified operators and act only at the direction of certified
operators. It concludes that an entity that does not exercise
operational authority should not be subject to the same requirements as
the decisionmaker.
1340. Northern Indiana states that it is not uncommon in the
industry for employees who perform switching operations to be
supervised by NERC-certified operators and that such employees are
subject to round-the-clock review by, and communication with, their
NERC-certified transmission operators. Similarly, SoCal Edison notes
that large utilities can have operators strategically located
throughout a vast service territory at switching centers with SCADA
capability and that these operators follow the directives of one
control center responsible for Bulk-Power System reliability. SoCal
Edison disagrees that the operators of these switching centers, simply
because the switching center has SCADA capability, must be NERC-
certified.
1341. LPPC states that the training and certification requirements
should apply only to transmission and generation personnel that are
located in the transmission control center (i.e., responsible for real-
time Bulk-Power System operations). It argues that transmission and
generation operation employees that are located in remote locations
that are not directly involved in the real-time scheduling of
transactions or Bulk-Power System monitoring and control do not need to
be certified for real-time operations because they are not involved in
the type of functions in which regimented training in the Reliability
Standards would be useful. It suggests that a bright line should be
drawn between the training of actual system operators and the training
for operators of generation plants that are not responsible for
scheduling. LPPC also states that the Commission should clarify the
scope of training that the transmission control center real-time
operations personnel should receive.
1342. Entergy asserts that the training program should be tailored
to the functions local control center operators, generator operators
and operations planning staff perform that impact the reliable
operation of the Bulk-Power System for both normal and emergency
operations.
(b) Commission Determination
1343. In our discussion above regarding the Functional Model, we
emphasized our concern that there should be no unintentional gaps or
redundancies in responsibility for compliance with the Requirements of
Reliability Standards. This concern arises particularly in the context
of RTOs, ISOs and other pooled resources that may have separate
divisions performing decisionmaking functions and implementing
functions within the transmission operator classification. The topic of
training is one such area of concern. While PER-002-0 applies to
transmission operators, it is important for reliability that personnel
involved in both decisionmaking and implementation receive proper
training.
1344. Clearly, in a region where an RTO or ISO performs the
transmission operator function, its personnel with primary
responsibility for real-time operations must receive formal training
pursuant to PER-002-0. In addition, personnel who are responsible for
implementing instructions at a local control center also affect the
reliability of the Bulk Power System. These entities may take
independent action under certain circumstances, for example, to protect
assets, personnel safety and during system restorations. Whether the
RTO or the local control center is ultimately responsible for
compliance is a separate issue addressed above, but regardless of which
entity registers for that responsibility, these local control center
[[Page 16544]]
employees must receive formal training consistent with their roles,
responsibilities and tasks. Thus, while we direct the ERO to develop
modifications to PER-002-0 to include formal training for local control
center personnel, that training should be tailored to the needs of the
positions.
1345. As noted by SoCal Edison, there are different operating
structures and therefore there is a need to clarify to which control
centers we direct the Reliability Standard apply. For example, for a
large utility within an RTO or ISO footprint there may be one
centrally-located control center whose function is to supervise several
distributed control centers, each with remote monitoring and control
capability. In this type of structure, the personnel of the centrally-
located control center should receive formal training in accordance
with the Reliability Standard. Personnel at the distributed control
centers also need to be trained, but the responsibility for this
training is outside the scope of the Reliability Standard.\368\
---------------------------------------------------------------------------
\368\ The Commission expects the entity registered as the
transmission operator to ensure that these personnel are competent
for the tasks that they perform.
---------------------------------------------------------------------------
1346. Another organizational structure, typically representative of
relatively smaller entities, consists of a single control center that
implements operating instructions from its transmission operator, e.g.,
an RTO, ISO or pooled resource. Similar to the discussion above,
operators at these control centers also may take independent action to
protect assets, safety and system restoration. Such control center
personnel must also receive formal training pursuant to PER-002-0.
1347. Consistent with the comments of SoCal Edison and Northern
Indiana, the Commission understands that it is common practice to have
traveling operators located in the local control centers who carry out
field switching operations and station inspections at the direction of
the local control center operators. These personnel are not involved
with the transmission operator at the ISO or RTO or at organizations
with pooled resources, and as such, should not be subject to
Reliability Standard PER-002-0.
1348. The Commission disagrees with those commenters who contend
that, because operators at local control centers take direction from
NERC-certified operators at the ISO or RTO, they do not need to be
addressed by the training requirements of PER-002-0. Rather, as
discussed above, these operators maintain authority to act
independently to carry out tasks that require real-time operation of
the Bulk-Power System including protecting assets, protecting personnel
safety, adhering to regulatory requirements and establishing stable
islands during system restoration.
1349. Several commenters express concern about requiring local
control center operators to become fully trained to the same extent as
transmission operators, balancing authorities and reliability
coordinators. This is not the Commission's intent. As we stated in the
NOPR, the proposed modifications do not imply a ``one-size-fits-all''
approach but rather ensure the creation of training programs that are
structured and tailored to the different functions and needs of the
personnel involved.\369\ Therefore the Commission agrees with Entergy
that the training program should be tailored to the functions local
control center operators, generator operators and operations planning
staff perform that impact the reliable operation of the Bulk-Power
System for both normal and emergency operations.
---------------------------------------------------------------------------
\369\ See NOPR at P 773, 775.
---------------------------------------------------------------------------
iii. Applicability to Generator Operators
1350. The Commission proposed in the NOPR a modification to PER-
002-0 to include real-time operations personnel from reliability
coordinators, generator operators, operations planning and operations
support staff in training programs with a time-phased effective
date.\370\
---------------------------------------------------------------------------
\370\ Id. at P 772.
---------------------------------------------------------------------------
(a) Comments
1351. PG&E and FirstEnergy support the Commission's goal of
ensuring appropriate training for generator operators. FirstEnergy,
however, believes that there is some confusion between the Functional
Model and the Reliability Standard requirements concerning the
generator operator classification. FirstEnergy explains that, in some
contexts, ``generator operator'' refers to operations personnel who are
centrally-located at a generation control center (i.e., fleet
operators) while in other contexts it refers to generator operators
located at the generation plant (i.e., unit operator). Further,
according to FirstEnergy, the NERC glossary defines ``generator
operator'' as the entity that operates generating unit(s) and performs
the functions of supplying energy and interconnected operations
services. FirstEnergy requests that the Commission direct NERC to
revise the Reliability Standard to recognize this distinction.
1352. Other commenters, including Xcel, California PUC and Entergy,
state that the Reliability Standard should not apply to generator
operators. Xcel argues that generator operators take their direction
from transmission operators, balancing authorities and reliability
coordinators, which limits their ability to exercise independent action
impacting the reliability of the Bulk-Power System. Entergy argues that
expanding the applicability to generator operators would provide little
benefit to those personnel in the performance of their own functions,
and could distract them from those functions. It also argues that such
training would be extremely costly and would divert necessary resources
from more important reliability objectives.
1353. California PUC states that the requirement to include power
plant operators in the applicability of this Reliability Standard
exceeds anything contemplated in the regulation of the Bulk-Power
System under previous NERC guidelines and what is authorized by
statute. It contends that impacts of generator operator actions on the
Bulk-Power System are of a much smaller magnitude and consequence than
those of system operators. Further, it states that other authorities,
such as balancing authorities and state governments, may have acted in
regard to training of power plant operators and, therefore, the
Commission should not act where other authorities have already done so.
In a similar vein, the Nevada Companies state that the activities of
generating station operations personnel are limited to the confines of
the specific generating station. Knowledge of or exposure to
interconnected grid operating principles is simply not applicable to
the tasks normally performed at the generating stations.
1354. Reliant states that the proposed modification fails to
clarify how generator operators are to satisfy the training program
requirement or the scope of generator operator personnel that must be
trained. It states that the proposed modification could be interpreted
to require generator operators to train the plant operator as well as
the dispatcher in the generator operator's local control center.
Reliant believes, however, that plant operators should not be subject
to the Reliability Standard's training program requirement because
personnel employed in plant operating positions are trained in the
operation of plant equipment and take direction with respect to the
operation of the plant from management personnel as well as from the
local control center. Accordingly, it reasons that, because
[[Page 16545]]
these employees take direction with respect to plant operations from
elsewhere, they do not have primary responsibility for the real-time
operation of the Bulk-Power System and should not be responsible for
complying with Reliability Standards. Reliant suggests that PER-002-0
should specifically target generator operator personnel that develop
dispatch instructions and the Reliability Standard should be modified
to accommodate generator operator entities that are members of ISOs and
RTOs with established NERC-approved certification programs. However, it
should exclude those personnel who simply take direction on plant
operations.
1355. Dynegy, MISO and Wisconsin Electric state that these
Reliability Standards should not be extended to all real-time operation
positions of a generator operator. They state that many real-time
operation positions are staffed by long-tenured union personnel who
routinely operate generating units and take directions from a
centralized generation control center or the local RTO/ISO. They
analogize this type of certification and training requirement with
requiring the outside field force of a transmission operator, including
positions that operate and switch electric transmission lines pursuant
to instructions from a centralized transmission control group, to be
NERC-certified. Dynegy and MISO support a more limited extension of
these Reliability Standards to real-time operation personnel located in
a centralized generation control center that interfaces with the plants
and the local RTO/ISO but not to personnel at the plant level.
1356. Some commenters address the appropriate scope of training for
generator operators. For example, MidAmerican states that experience
and knowledge necessary for transmission operators may go well beyond
what is needed for generation operations. It contends that a NERC-
approved training course specific to these functions would be an
appropriate alternative. Entergy comments that, if training of
generator operator personnel is required, it should focus on the
functions generator operators must perform, not on the functions that
others perform. SDG&E states that training for generator operators and
others who may directly impact the reliable operations of the Bulk-
Power System need not be identical to or as extensive as that required
of transmission system operators, but should be tailored in scope,
contents and duration so as to be appropriate to the personnel and the
object of promoting system reliability.
1357. FirstEnergy states that there are no universal certification
or training programs for generator operators; therefore a reasonable
transition period should be established to allow time for generator
operators to comply with this Reliability Standard. It also states that
nuclear units are already subject to NRC training requirements and that
compliance with NRC requirements should satisfy this Reliability
Standard.
1358. APPA, Process Electricity Committee and TAPS are concerned
that, unless a size limitation is included for the generator operators,
a substantial number of generator operator personnel will have to be
enrolled in training programs. They argue that while a generator plays
an important role in the reliable operations of the bulk electric
system, the generator operator takes commands from the transmission
operator, balancing authority or reliability coordinator. TAPS opposes
the expanded applicability, especially in the case of small systems,
because it believes that the requirement would be costly with no
benefits to reliability.
1359. Process Electricity Committee is concerned about the effect
of the expanded requirements on end users who have on-site generation.
It argues that the training requirements would present an added cost
for end users with no apparent added benefit and that, in the long
term, end users may be discouraged from developing on-site generation,
which in turn would leave industrial electricity users more vulnerable
to failures elsewhere on the energy grid.
(b) Commission Determination
1360. The Commission explained in the NOPR that transmission
operators and balancing authorities are not the only entities that have
operating personnel in positions that directly impact the reliable
operation of the Bulk-Power System; and included generator operators
among those that have such an impact.\371\ Xcel and others oppose
extending the applicability of PER-002-0 to generator operators,
because they take directions from balancing authorities and others,
which limits their ability to impact reliability. Although a generator
may be given direction from the balancing authority, it is essential
that generator operator personnel have appropriate training to
understand those instructions, particularly in an emergency situation
in which instructions may be succinct and require immediate action.
Further, if communication is lost, the generator operator personnel
should have had sufficient training to take appropriate action to
ensure reliability of the Bulk-Power System. Thus, we direct the ERO to
develop a modification to make PER-002-0 applicable to generator
operators.
---------------------------------------------------------------------------
\371\ NOPR at P 771.
---------------------------------------------------------------------------
1361. We agree with FirstEnergy and others that some clarification
is required regarding which generator operator personnel should be
subject to formal training under the Reliability Standard. As noted
above, a generator operator typically receives instructions from a
balancing authority. Some generator operators are structured in such a
way that they have a centrally-located dispatch center that receives
direction and then develops specific dispatch instructions for plant
operators under their control. For example, a balancing authority may
direct a centrally-located dispatch center to deliver 300 MW to the
grid, and the dispatch center would determine the best way to deliver
that generation from its portfolio of units. In this type of structure,
it is the personnel of the centrally-located dispatch center that must
receive formal training in accordance with the Reliability Standard.
Plant operators located at the generator plant site also need to be
trained but the responsibility for this training is outside the scope
of the Reliability Standard.\372\
---------------------------------------------------------------------------
\372\ The Commission expects the entity registered as the
generator operator to ensure that plant operators are competent for
the tasks that they perform.
---------------------------------------------------------------------------
1362. Other generator operators may be structured in such a way
that the dispatch center and the single generation plant are at the
same site. In this structure as well, some personnel will perform
dispatch activities while others are designated as plant operators.
Again, it is the dispatch personnel that must receive formal training
in accordance with the Reliability Standard. Plant operators also need
to be trained but the responsibility for this training is outside the
scope of the Reliability Standard.
1363. We disagree with Nevada Companies, Xcel and others that
assert that generator operator training will provide limited benefit.
Rather, we conclude that, with the above focused direction regarding
the applicability of the Reliability Standard to generator operator
personnel, the benefits to the Bulk-Power System will be maximized and
the cost of formal training limited. Further, our direction addresses
California PUC's concerns regarding application to plant operators. In
any event, the existence of local training requirements in some regions
does not supplant the need for uniform training requirements for all
generator operators
[[Page 16546]]
developed in a Reliability Standard with continent-wide applicability.
1364. Further, the Commission agrees with MidAmerican, SDG&E and
others that the experience and knowledge required by transmission
operators about Bulk-Power System operations goes well beyond what is
needed by generation operators; therefore, training for generator
operators need not be as extensive as that required for transmission
operators. Accordingly, the training requirements developed by the ERO
should be tailored in their scope, content and duration so as to be
appropriate to generation operations personnel and the objective of
promoting system reliability. Thus, in addition to modifying the
Reliability Standard to identify generator operators as applicable
entities, we direct the ERO to develop specific Requirements addressing
the scope, content and duration appropriate for generator operator
personnel.
1365. FirstEnergy states that nuclear plant operators are already
subject to NRC training requirements and thus suggests that compliance
with NRC requirements should satisfy this Reliability Standard.
FirstEnergy does not identify the content of the NRC training
requirements, and the Commission is unaware whether the NRC training
requirements adequately address the interaction between a nuclear power
plant and the Bulk-Power System. Accordingly, without drawing any
conclusion on the matter, the Commission directs that the ERO consider
FirstEnergy's comments in the Reliability Standards development
process.
1366. Commenters' concerns regarding the need for a size limitation
on generator operators should be satisfied by our determination that
the applicability of particular entities should be determined based on
the ERO compliance registry criteria, which APPA and TAPS support. We
believe that limiting the applicability of Reliability Standards to
NERC's definition of bulk electric system will alleviate much of
Process Electricity Committee's concern regarding the effect of the
expanded requirements on end users who have on-site generation. For
larger end users who have on-site generation, the Commission believes
that there is an added benefit to including them in the Reliability
Standards because they sell into the market and should be treated on a
similar basis as any other generator of a similar size.
iv. Applicability to Operations Planning and Operations Support Staff
1367. As mentioned above, the Commission proposed in the NOPR to
direct the ERO to develop a modification to PER-002-0 to require
training of operations planning and operations support staff of
transmission operators and balancing authorities who have a direct
impact on the reliable operation of the Bulk-Power System.
(a) Comments
1368. Several commenters, including EEI and APPA, oppose the
proposed applicability of the Reliability Standard to operations
planning and operations support staff. Other commenters contend that
the Commission's proposal is ambiguous and should be clarified.
1369. EEI states that the extension of the applicability to
``operations support personnel'' could result in a dramatic expansion
of industry training requirements with uncertain benefits to system
reliability. It requests that the Commission reconsider this proposal
or provide some additional clarity on the definition of the term. APPA
also expresses concern about expanding the applicability to operations
planning and operations support staff, especially if the Commission
adopts its proposed interpretation of the bulk electric system because
this would become quite onerous for small utilities. Wisconsin Electric
states that the Commission's proposal does not address how to identify
the operations planning and operations support personnel who would be
subject to the Reliability Standard and how to develop compliance
measures for them. It contends that the proposed modification is
ambiguous and should not be implemented.
1370. Avista states that individuals who are responsible for
assessing a company's compliance with the Reliability Standards may
simply have an administrative and coordination role, but have no direct
responsibility for reliable operations of the Bulk-Power System. It
argues that such individuals, while operations support staff, should
not be subject to the proposed Reliability Standard. It therefore
requests that the Commission clarify that personnel subject to the
Reliability Standard may include operations planning and operations
support staff.
1371. Entergy believes it is unnecessary to require all staff
supporting the transmission operator to be trained in the transmission
operator's Reliability Standards responsibilities. It states that as
long as the supporting personnel work under the direction of a NERC-
certified transmission operator, there is no need for duplicative
training for supporting personnel. Entergy comments that, if such
training is required, it should focus on the functions operations
planning and operations support staff must perform, not on the
functions that others perform.
1372. Northern Indiana states that expanding application of the
Reliability Standard to operations support staff ``with a direct impact
on the reliable operation of the Bulk-Power System'' is ambiguous. It
states that NERC surveyed certified operators for its job function
analysis related to this Reliability Standard with results due at the
end of January 2007. Northern Indiana recommends that the results of
this survey be considered in the development and clarification of this
proposed Reliability Standard. Further, Northern Indiana is concerned
about which specific job functions will be addressed and which will be
exempt, and about what ``direct'' versus ``indirect'' impact means.
(b) Commission Determination
1373. The Commission directs the ERO to develop a modification to
PER-002-0 that extends applicability to the operations planning and
operations support staff of transmission operators and balancing
authorities, as clarified below. Most commenters express concern about
extending the applicability of the Reliability Standard because they
believe ``operations planning'' and ``operations support'' are not
well-defined and could encompass a significant number of operations
personnel. In the NOPR, the Commission stated that the Reliability
Standard should apply to operations planning and operations support
staff that have a direct impact on the reliable operation of the Bulk-
Power System.\373\ We clarify that these personnel include those who
carry out outage coordination and assessments in accordance with
Reliability Standards IRO-004-1 and TOP-002-2, and those who determine
SOLs and IROLs or operating nomograms in accordance with Reliability
Standards IRO-005-1 and TOP-004-0. The Commission directs the ERO to
include in PER-002-0, personnel who carry out the above functions.
---------------------------------------------------------------------------
\373\ NOPR at P 780.
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1374. In addition, the Commission is aware that the personnel
responsible for ensuring that critical reliability applications of the
EMS, such as state estimator, contingency analysis and alarm processing
packages, are available, up-to-date in terms of system
[[Page 16547]]
data and produce useable results can also have an impact on the
Reliable Operation of the Bulk-Power System. Because these employees'
impact on Reliable Operation is not as clear, we direct the ERO to
consider, through the Reliability Standards development process,
whether personnel that perform these additional functions should be
included in mandatory training pursuant to PER-002-0.
1375. APPA and EEI oppose the proposed extension of the Reliability
Standard to operations planning and operations support staff, claiming
that it could dramatically expand industry training requirements with
uncertain benefits to system reliability. Our clarification above
adequately addresses these concerns because we have identified a
specific set of such personnel that have a direct impact on reliable
operations. With the above clarification, our directive is not as
expansive as EEI and APPA contemplate, and is more clearly connected
with Bulk-Power System reliability. Further, since the Commission is
not adopting the proposed interpretation of the ERO's definition of
bulk electric system, as discussed in the Applicability section above,
the directed modification to PER-002-0 should not be onerous to small
entities as suggested by APPA.
1376. Several commenters express concern that the operations
planning and operations support staffs will be required to be trained
on the transmission operators' responsibilities. The Commission
clarifies that this is not the case. Training programs for operations
planning and operations support staff must be tailored to the needs of
the function, the tasks performed and personnel involved.
v. Training Performance Metrics
1377. In the NOPR, we noted the assertion by ISO/RTO Council that
there is no definition for ``adequately trained operating personnel.''
ISO/RTO Council suggested adoption of performance metrics to ensure
that training results in competent operating personnel.\374\ The
Commission agreed and proposed to require that the ERO modify PER-002-0
to include performance metrics to assess the effectiveness of the
training program. The Commission also stated that such performance
metrics are not a substitute for an SAT developed training program.
---------------------------------------------------------------------------
\374\ Id. at P 776.
---------------------------------------------------------------------------
(a) Comments
1378. Xcel does not agree that performance metrics should be
included as part of this Reliability Standard. While it believes
performance metrics are generally useful, it states that in this case
it would be difficult to develop the appropriate metrics. MidAmerican
believes that the proposed performance metrics are not essential to
ensuring the appropriateness of training because the Reliability
Standard already requires NERC approval of all training activities, and
specifically requires training in certain areas.
1379. MISO and Wisconsin Electric state that it is unclear how a
Reliability Standard to measure the effectiveness of a training program
would apply to an organization that contracts for training services,
and that there are many training requirements found in other
Reliability Standards covering the topics and amount of training. They
argue that the proposed modification is overly-prescriptive and
deviates from a fundamental training concept that training should be
tailored to the organization and to the individual.
(b) Commission Conclusion
1380. Xcel, MISO and MidAmerican state that performance metrics to
assess the effectiveness of training programs are unnecessary. The
Commission believes that, if quantifiable performance metrics can be
developed to gauge the effectiveness of a Reliability Standard, these
performance metrics should be developed, tracked and used to
continually improve an applicable entity's performance and the
Reliability Standard itself. The Commission directs the ERO to explore
the feasibility of developing meaningful performance metrics for
assessing the effectiveness of training programs, and if feasible, to
develop such metrics for the Reliability Standard as part of the
Reliability Standards development process.
vi. Use of Systematic Approach to Training (SAT) Methodology
1381. In the NOPR, the Commission required the ERO to use the SAT
methodology in identifying the requirements for a training program
because SAT is a proven approach to: identify the tasks and associated
skills and knowledge necessary to accomplish those tasks; determine the
competency levels of each operator to carryout those tasks; determine
the competency gaps; and design, implement and evaluate a training plan
to address each operator's competency.\375\
---------------------------------------------------------------------------
\375\ Id. at P 775.
---------------------------------------------------------------------------
(a) Comments
1382. ISO-NE states that the use of SAT methodology should not be
mandated and that responsible entities under this Reliability Standard
should be allowed the flexibility to use the most appropriate training
methodology available. Northern Indiana requests clarification on about
our proposal on the use of SAT methodology.
(b) Commission Determination
1383. The Commission understands that the new operator training
Reliability Standard PER-005-1-0 currently under development by the ERO
would endorse the use of SAT. In response to ISO-NE, training based on
SAT is a proven approach to identify the skills and knowledge necessary
to accomplish particular tasks, evaluate each operator's competency to
carry out those tasks, determine any competency competency gaps, and
design, implement and evaluate a training plan to address such gaps.
Since SAT is the most appropriate training methodology available, we
believe this addresses ISO-NE's comments. Northern Indiana requests
clarification about the details of our proposal for SAT methodology.
The Commission has not directed how the SAT methodology should be
implemented, but we expect it to be developed through the Reliability
Standards development process. We encourage Northern Indiana to become
involved in the process. Thus, we adopt the NOPR proposal to direct
that the ERO develop a modification to PER-002-2 (or a new Reliability
Standard) that uses the SAT methodology.
vii. Use of Simulators for Training
1384. The Commission explained in the NOPR that Requirement R4 of
the Reliability Standard requires training in emergency operations
using realistic simulations of system emergencies and noted that there
are various options available for providing operator training simulator
capability, including contracting for this service from others who have
developed the capability. The Commission requested comments on the
benefits and appropriateness of required ``hands-on'' training using
simulators in dealing with system emergencies.\376\
---------------------------------------------------------------------------
\376\ Id. at P 778.
---------------------------------------------------------------------------
(a) Comments
1385. While most commenters recognize the benefits of simulator
training, they differ on whether simulator training should be
mandatory.
1386. NERC comments that there can be significant value gained by
training operating personnel for emergencies under realistic conditions
using training simulators and requests that comments on this matter be
directed to the
[[Page 16548]]
Reliability Standards development process for consideration. APPA
believes that significant reliability benefits could result from the
use of simulators by reliability coordinators, transmission operators
and balancing authorities that have operational control over a
significant portion of load and resources. It does not believe,
however, that requiring simulator training for smaller entities that do
not have operational control over facilities that manage SOLs and IROLs
would be an effective use of resources. APPA supports NERC's
investigating the benefits of simulator training but recommends that
any training requirements closely consider the costs and benefits of
simulator training.
1387. SoCal Edison and MISO state that, although simulators are
valuable training tools, not all entities should be compelled to have
simulators. MISO comments that simulators will become even more
critical in the coming years as experienced operators, with first-hand
knowledge of their respective systems, retire. Recognizing that not
every company can or should build a simulator because of the resources
simulators require, MISO suggests that the Reliability Standards codify
a requirement for operators of companies that do not own a simulator to
have access to a training simulator. MISO states that while simulators
are valuable training resources, focusing emergency training solely on
full-scale simulators may lead to problems when unforeseen situations
arise. It reasons that generic, low-cost simulators that teach concepts
are a valuable training resource for developing skills transferable to
events that do not follow a script.
1388. SDG&E states that simulators would enhance the overall
training experience but cautions that simulators that accurately model
individual systems are resource-consuming while less resource-
consuming, generic simulators may not mirror the trainee's actual
system. As such, it believes that the use of simulators should be
encouraged but not mandated. Similarly, International Transmission
contends that simulators are a useful tool in the training of operators
and support personnel. However it cautions that simulators are not the
only means to provide realistic simulation-based training. It argues
that because alternative simulation-based training means are available
and because dedicated training simulators are very expensive, the use
of dedicated training simulators should not be required under the
Reliability Standards.
1389. Otter Tail states that full-scale simulators are effective
but costly to develop and labor intensive to maintain. It recommends
that full-scale simulators should be an option but not a requirement
for small entities. It proposes instead that the Commission allow small
entities to continue to use training aids such as generic operator
training simulators, EXCEL-based interactive training tools and table-
top training exercises. Likewise, Alcoa also does not believe that
simulators are necessary to provide operating personnel with training
for system emergencies. It supports alternative training methods, such
as table-top exercises or realistic simulated exercises that take into
account the physical and electrical characteristics of the trainee's
system. Further, it believes that costs associated with simulators
would not be justified by the impact on reliability.
1390. Xcel states that to the extent that Reliability Standard PER-
002-0 is applicable to generator operators, the industry should be able
to develop its own ways of administering training instead of being
required to develop simulators.
(b) Commission Determination
1391. Most commenters including NERC agree that hands-on training
using simulators can add significant value to training for emergencies.
Yet, we share the commenters' concerns regarding the high cost to
develop and maintain full-scale simulators and take these concerns into
consideration. The Commission finds that significant reliability
benefits may be derived from requiring simulator training for
reliability coordinators, transmission operators and balancing
authorities that have operational control over a significant portion of
load and generation.
1392. This does not mean that these entities must develop and
maintain full-scale simulators but rather they should have access to
training on simulators. Further, because the cost is likely to outweigh
the reliability benefits for small entities, the Commission agrees with
Alcoa and Otter Tail that small entities should continue to use
training aids such as generic operator training simulators and
realistic table-top exercises. Accordingly, the Commission directs the
ERO to develop a requirement for the use of simulators dependent on the
entity's role and size, as discussed above.
viii. Summary of Commission Determination
1393. The Commission notes that no commenters specifically
addressed the proposed modifications directing the ERO to expand the
Applicability section to include reliability coordinators, and to
identify the expectations of the training for each job function and
develop training programs tailored to each job function with
consideration of the individual training needs of the personnel.
However, in responding to the proposals to expand the applicability of
the Reliability Standard, many commenters acknowledged the need to have
clear training expectations and training programs tailored to specific
job functions. The Commission finds that these two modifications will
enhance the training by focusing on expectations and tailoring the
training to specific job functions; therefore, the Commission adopts
these modifications to the Reliability Standard.
1394. Accordingly, the Commission approves Reliability Standard
PER-002-0. In addition, pursuant to section 215(d)(5) of the FPA and
Sec. 39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to PER-002-0 through the Reliability Standards
development process that: (1) Identifies the expectations of the
training for each job function; (2) develops training programs tailored
to each job function with consideration of the individual training
needs of the personnel; (3) expands the Applicability section to
include (a) reliability coordinators, (b) local transmission control
center operator personnel (as specified in the above discussion), (c)
generator operators centrally-located at a generation control center
with a direct impact on the reliable operation of the Bulk-Power System
and (d) operations planning and operations support staff who carry out
outage planning and assessments and those who develop SOLs, IROLs or
operating nomograms for real-time operations; (4) uses the Systematic
Approach to Training (SAT) methodology in its development of new
training programs and (5) includes the use of simulators by reliability
coordinators, transmission operators and balancing authorities that
have operational control over a significant portion of load and
generation.
1395. Further, the Commission directs the ERO to determine whether
it is feasible to develop meaningful performance metrics associated
with the effectiveness of a training program required by PER-002-0 and,
if so, develop such performance metrics. The Commission also directs
the ERO to consider through the Reliability Standards development
process, whether personnel that support EMS applications as discussed
above should be included in mandatory training pursuant to the
Reliability Standard.
[[Page 16549]]
c. Operating Personnel Credentials (PER-003-0)
1396. PER-003-0 requires transmission operators, balancing
authorities and reliability coordinators to have NERC-certified staff
for all operating positions that have a primary responsibility for
real-time operations or are directly responsible for complying with the
Reliability Standards. NERC grants certification to operating personnel
through a separate program documented in the NERC System Operator
Certification Manual and administered by an independent personnel
certification governance committee.
1397. In the NOPR, the Commission proposed to approve Reliability
Standard PER-003-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to PER-003-
0 that: (1) Includes generator operators as applicable entities; (2)
specifies the minimum competencies that must be demonstrated to become
and remain a certified operator; and (3) identifies the minimum
competencies operating personnel must demonstrate to be certified.
i. Comments
1398. In addressing this Reliability Standard, many commenters made
the same arguments they made in connection with the operator training
Requirements set forth in Reliability Standard PER-002-0. Comments
specifically relevant to operator certification are reproduced here for
completeness.
1399. EEI, FirstEnergy and PG&E agree that the Reliability Standard
should apply to generator operators. FirstEnergy believes that the
Functional Model and the Reliability Standards development process
should be used to clarify any confusion about which generator operator
and transmission operator functions are addressed under this
Reliability Standard. To further reduce confusion and the need for
potentially duplicative training, EEI and PG&E comment that operators
should not be required to maintain multiple certifications. SDG&E
states that new certification obligations for generator operators must
be tailored to the needs of the function and should reflect the limited
opportunities of generator operators to have an impact on system
reliability. Thus, it argues that generator operators should not be
subject to the same certification requirements as transmission
operators. MidAmerican echoes this point and adds that minimum
competencies are currently adequately demonstrated by the completion of
NERC-approved annual certification tests. MidAmerican believes that
applicable tests should be tailored to specific job duties to ensure
effectiveness and Reliability Standard compliance.
1400. Dynegy, MISO, Reliant and Wisconsin Electric are concerned
about extension of this Reliability Standard to generator operators if
it results in every power plant control room being staffed by NERC-
certified operators. Dynegy supports a limited extension of the
Reliability Standard to real-time operational personnel located in a
centralized generation control center that interfaces with the plants
and the local RTO/ISO. Reliant believes that, under certain
circumstances, the dispatcher in the generator operator's local control
center should not be subject to NERC certification requirements. It
explains that, for example, in PJM the dispatcher in a generator
operator local control center is a PJM-certified generation dispatcher
and that, like the employees in plant operating positions, these
dispatchers do not take unilateral action but instead act only upon
PJM's instructions.
1401. LPPC states that certification requirements for real-time
operations Reliability Standards should only be required for
transmission and generation personnel that are located in the
transmission control center (i.e., responsible for real-time Bulk-Power
System operations). It argues that transmission and generation
operation employees that are located in remote locations that are not
directly involved in the real-time scheduling of transactions or Bulk-
Power System monitoring and control do not need to be certified for
real-time operations Reliability Standards because they are not
involved in the type of functions in which regimented training in the
Reliability Standards would be useful. LPPC states that requiring
certification would be an inefficient result and would distract these
personnel from their own highly-specialized tasks.
1402. Although APPA states that PER-003-0 is sufficient for
approval as a mandatory and enforceable Reliability Standard, it
opposes the proposed modification to make generator operators subject
to the Reliability Standard. Alcoa, Entergy, Northern Indiana and Xcel
also oppose subjecting generator operators to the Reliability Standard.
Given that there is no size limitation limiting applicability for
generator operators, APPA asks the Commission to reconsider the
proposed modification and, instead, allow the applicability of PER-003-
0 to generator operators to be considered through the Reliability
Standards development process. Alcoa disagrees with the proposed
modification because generator operators take direction from a NERC-
certified transmission operator, balancing authority or reliability
coordinator and do not operate independently of those entities.
Similarly, Xcel states generator operators have limited ability to take
independent action that affects Bulk-Power System reliability. It also
states that it is not clear whether ``generator operator'' means plant
operator or the transmission operator responsible for generation.
1403. Northern Indiana and SoCal Edison oppose a certification
requirement for all real-time operating positions in a transmission
control center that performs switching operations via SCADA for the
Bulk-Power System, because these personnel are supervised by NERC-
certified operators. Northern Indiana states that the costs would far
outweigh the reliability benefits, if any, that would result from such
a certification requirement. SoCal Edison recommends that PER-003-0
apply to operators who have the authority and are empowered to exercise
independent judgment, and who take or direct actions to secure Bulk-
Power System reliability. It recommends that operators who switch Bulk-
Power System facilities when their actions are approved and overseen by
certified operators should be excluded.
1404. APPA states that if it is required to send its employees for
NERC training and certification, it would risk losing those employees
to larger utilities that can afford to pay more, simply because those
employees would have acquired a desirable occupational credential. It
argues that given the substantial workforce issues facing public power
systems in the next few years, imposing unneeded certification
requirements could exacerbate an already challenging labor force
situation.
1405. Northern Indiana adds that because some of these employees
are members of labor unions and subject to existing collective
bargaining agreements, it would have to renegotiate these agreements to
provide for the certification of these employees, and to provide for
the hiring of relief staff necessary to permit these employees to
maintain their certification.
1406. PG&E states that, once the certification requirements are
developed by NERC and approved by the Commission, sufficient time must
be permitted for generator operators to attain the necessary
certification. It argues that time will be needed to
[[Page 16550]]
develop the process, create appropriate documentation and perform
training for appropriate personnel. PG&E contends that generator
operators should not be penalized for failing to achieve certification
if they do not have a reasonable period of time to implement the
training programs.
1407. EEI believes that the ERO's Reliability Standards development
process should be used to sort out the applicability issues. It states
that using this process will allow for sufficient clarity to reduce the
risk of confusion and thus prevent the need for interpretations that
could change over time. EEI believes this is especially important with
this PER class of Reliability Standards because operators should have
unambiguous guidance on what they are expected to do. It states that
the Reliability Standards should be written so that operating personnel
clearly understand their roles and responsibilities, and whether or not
a specific certification is required. EEI also states that operators
should not be required to maintain multiple certifications.
ii. Commission Determination
1408. Northern Indiana and APPA raise persuasive arguments
regarding labor relations and labor retention issues that may arise if
generator operators are required to be NERC-certified. The Commission
understands theses concerns and is persuaded not to require generator
operators or transmission operators at local control centers to be
NERC-certified at this time. In addition, the Commission understands
that there are some long tenured unionized transmission operators who
are very capable operators but who are unable to secure certification.
This is not a new problem and has been addressed in various collective
bargaining negotiations through grandfathering such capable operators
who are unable to become certified. However, the Commission directs
that if grandfathering is implemented, the entity must attest that the
operators are competent. The Commission directs the ERO to consider
grandfathering certification requirements for these personnel so that
the industry can retain the knowledge and skill of these long-tenured
operators. Personnel that are subject to such grandfathering still must
comply with applicable training requirements pursuant to PER-002-0.
1409. No comments were received on the proposed modifications to
direct the ERO to modify the Reliability Standard to specify the
minimum competencies that must be demonstrated to become and remain a
certified operator and to identify the minimum competencies operating
personnel must demonstrate to be certified. The Commission finds that
these modifications improve the Reliability Standard by focusing on
necessary competencies. Accordingly, the Commission directs the ERO to
develop these modifications to the Reliability Standard.
1410. We find that the Reliability Standard serves an important
reliability goal in requiring applicable entities to staff all
operating positions that have a primary responsibility for real-time
operations or are directly responsible for complying with the
Reliability Standards with NERC-certified staff. Accordingly, the
Commission approves Reliability Standard PER-003-0. In addition,
pursuant to section 215(d)(5) of the FPA and Sec. 39.5(f) of our
regulations, the Commission directs the ERO to develop a modification
to PER-003-0 through the Reliability Standards development process
that: (1) Specifies the minimum competencies that must be demonstrated
to become and remain a certified operator and (2) identifies the
minimum competencies operating personnel must demonstrate to be
certified. The Commission also directs the ERO to consider
grandfathering certification requirements for transmission operator
personnel in the Reliability Standards development process.
d. Reliability Coordination--Staffing (PER-004-1)
1411. PER-004-1 ensures that reliability coordinator personnel are
adequately trained, NERC-certified and staffed 24-hours a day, seven
days a week, with properly trained and certified individuals.\377\
Further, reliability coordinator operating personnel must have a
comprehensive understanding of the area of the Bulk-Power System for
which they are responsible.
---------------------------------------------------------------------------
\377\ In its November 15, 2006, filing, NERC submitted PER-004-
1, which supercedes the Version 0 Reliability Standard. PER-004-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, PER-004-1.
---------------------------------------------------------------------------
1412. In the NOPR, the Commission proposed to approve Reliability
Standard PER-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 proposed to direct NERC to submit a modification to PER-
004-0 that: (1) Includes formal training requirements for reliability
coordinators similar to those addressed under the personnel training
Reliability Standard PER-002-0; (2) includes requirements pertaining to
personnel credentials for reliability coordinators similar to those in
PER-003-0 and (3) includes Measures and Levels of Non-Compliance that
address staffing requirements and the requirement for five days of
emergency training.
i. Comments
1413. APPA notes that the revised Reliability Standard PER-004-1
filed by NERC on November 15, 2006 partially fulfills the directive to
include Measures and Levels of Non-Compliance. It states that NERC
should be directed to include Measures and Levels of Non-Compliance
related to all Requirements.
1414. FirstEnergy seeks revisions to the terms ``shall have a
comprehensive understanding'' and ``shall have extensive knowledge.''
It states that it will be difficult for entities to demonstrate
compliance with these terms. In addition, FirstEnergy suggests that the
reliability coordinator staffing requirements should be located in the
IRO Reliability Standards.
1415. Xcel states that emergency training requirements should be
expressed in hour increments rather than days to allow for flexibility
in scheduling training and coordinating with rotating shift schedules.
ii. Commission Determination
1416. No comments were received on the proposed modifications to
include formal training requirements for reliability coordinators
similar to those addressed under the personnel training Reliability
Standard PER-002-0 and to include requirements pertaining to personnel
credentials for reliability coordinators similar to those in PER-003-0.
The Commission finds that these modifications will improve the
Reliability Standard because they include training requirements for the
reliability coordinator who has the highest level of authority to
assure Reliable Operation of the Bulk-Power System. Accordingly, the
Commission directs the ERO to develop modifications to the Reliability
Standard that address these matters.
1417. With regard to APPA's comments, consistent with our
discussion above regarding Measures and Levels of Non-Compliance, we
leave it to the discretion of the ERO whether it is necessary that each
Requirement of this Reliability Standard have a corresponding Measure.
1418. We find that the Reliability Standard adequately addresses
reliability coordinator staffing. Accordingly, the Commission approves
Reliability Standard PER-004-1. In
[[Page 16551]]
addition, pursuant to section 215(d)(5) of the FPA and Sec. 39.5(f) of
our regulations, the Commission directs the ERO to develop a
modification through the Reliability Standards development process to
PER-004-1 that: (1) Includes formal training requirements for
reliability coordinators similar to those addressed under the personnel
training Reliability Standard PER-002-0 and (2) includes requirements
pertaining to personnel credentials for reliability coordinators
similar to those in PER-003-0. Further, we direct the ERO to consider
the suggestions of FirstEnergy and Xcel in the Reliability Standards
development process.
10. PRC: Protection and Control
1419. Protection and Control systems (PRC) on Bulk-Power System
elements are an integral part of reliable grid operation. Protection
systems are designed to detect and isolate faulty elements on a system,
thereby limiting the severity and spread of system disturbances, and
preventing possible damage to protected elements. The function,
settings and limitations of a protection system are critical in
establishing SOLs and IROLs. The PRC Reliability Standards apply to
transmission operators, transmission owners, generator operators,
generator owners, distribution providers and regional reliability
organizations and cover a wide range of topics related to the
protection and control of power systems.
a. System Protection Coordination (PRC-001-1)
1420. PRC-001-1 \378\ ensures that protection systems are
coordinated among operating entities by requiring transmission and
generator operators to notify appropriate entities of relay or
equipment failures that could affect system reliability. In addition,
transmission and generator operators must coordinate with appropriate
entities when new protection systems are installed, or when existing
protection systems are modified.
---------------------------------------------------------------------------
\378\ In its November 15, 2006, filing, NERC submitted PRC-001-
1, which supercedes the Version 0 Reliability Standard. PRC-001-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, PRC-001-1.
---------------------------------------------------------------------------
1421. In the NOPR, the Commission proposed to approve PRC-001-0 as
mandatory and enforceable. In addition, the Commission proposed to
direct NERC to submit modifications to PRC-001-0 (proposed directives)
that included: (1) Measures and Levels of Non-Compliance; (2) a
requirement that transmission and generator operators be informed
immediately upon the detection of failures in relays or protection
system elements on the Bulk-Power System that would threaten reliable
operation, so that these entities could carry out appropriate
corrective control actions consistent with those used in mitigating
IROL violations and (3) clarifying that, after being informed of
failures in relays or protection system elements on the Bulk-Power
System, transmission operators or generator operators carry out
corrective control actions that return a system to a stable state as
soon as possible, but no longer than 30 minutes after receiving a
notice of failure.
i. Comments
1422. While Constellation supports the Commission's proposed
directives because they represent additional steps to achieving
reliability of the Bulk-Power System and eliminating undue
discrimination, MISO questions the need for the Commission's proposals.
MISO notes that virtually all protection schemes have backups. MISO
asks whether the Commission wants facilities to be removed from service
if one of the redundant relaying packages has a problem, or whether
some other action should be taken besides such removal.
1423. With regard to the NOPR's direction to the ERO to include
Measures and Levels of Non-Compliance, APPA states that the new
Measures only partially address the Requirements, and in some cases,
reference non-existent Requirements. For example, rather than
referencing Requirement R5.1, new Measure M1 incorrectly refers to non-
existent Requirement R8.1. Similarly, rather than referencing
Requirement R5.2, new Measure M2 incorrectly refers to non-existent
Requirement R8.2.
1424. APPA states that while it agrees that PRC-001-1 is sufficient
for approval, since the new Measures only partially address the
Requirements, and in some cases refer to non-existent Requirements, no
penalties should be levied for violations of Requirements that have no
accompanying Measures.
1425. WIRAB states that the Requirements, Measures and Levels of
Non-Compliance do not provide guidance for the length of time--
currently stated as ``as soon as possible''--permitted for corrective
actions.
1426. APPA disagrees with the Commission's second and third
directives to NERC. APPA states that the BAL and IRO Reliability
Standards already have specific standards to notify affected entities
and provide directions for recovery time. APPA acknowledges that in the
NOPR, we stated that ``the Reliability Standards on mitigating IROL
violations are not specific enough and system operators or field
protection and control personnel would not be alerted about failures of
relays and protection systems on critical elements.'' APPA, however,
states that: ``If this is the Commission's view, then it should
instruct NERC to re-examine the interaction between these two sets of
standards [IROL and SOL and proposed PRCs] on remand, and to develop
the most efficient solution to this problem. The Commission should not
itself undertake to resolve this problem by issuing directives for
specific revisions to PRC-001-1, especially if the result might be to
have local level personnel countermanding the instruction of RC
personnel at a time when the system is unstable.'' APPA asserts that
the Commission should modify its proposed directives to allow NERC, as
technical expert, to address the problems in the Reliability Standard
that the Commission has identified.
1427. Dynegy states that in many situations, depending on the
particular relay or protection system failure, an operator may not be
able to complete corrective control actions that return the system to a
stable state within 30 minutes, including troubleshooting of relays or
restoring any tripped facilities. Dynegy find that a 30-minute time
period may thus be overly rigid and punitive. Wisconsin Electric also
requests further clarification of the 30-minute time limit to carry out
corrective actions after a relay failure. It has additional concerns
about older relays (e.g., electromechanical relays) since it is
impossible to know when and whether these older relays have failed.
Wisconsin Electric also states that the NOPR is not clear about which
relays threaten reliable system operation.
1428. Northern Indiana states that the NOPR appears to require
immediate corrective actions whenever failures on relays or protection
systems are detected, without regard to whether the specific failure
detected reduces system reliability. It seeks the Commission's
clarification that we do not intend to question a certified
transmission operator's expertise in assessing whether a particular
relay or protection system failure reduces system reliability.
1429. California PUC contends that imposing a time restriction for
returning a system to a stable state may cause more harm than good
since additional information and options may be available as time
elapses. It repeats its suggestion from its earlier comments on
[[Page 16552]]
the Staff Preliminary Assessment and proposes the following alternative
language: ``Transmission or generation operators shall carry out
corrective control actions, i.e., returning the system to a stable
state that respects system requirements as soon as possible, and no
longer than 30 minutes, except where a longer response time is
feasible, or where a longer response is demonstrated to produce a
better ultimate solution without unacceptable interim risk.''
1430. A number of commenters raise concerns that the proposal would
be unnecessarily burdensome on generator operators. For example,
Progress Electricity Committee asserts that the Commission's proposal
to require generator operators to return the system to a stable state
as soon as possible and within no longer than 30 minutes may be too
burdensome for non-energy company users with on-site generation.
California Cogeneration asserts that PRC-001-1 as a whole may impose
unreasonable burdens on generators with no material impact on the grid,
because most such generators will have no knowledge of the protection
systems on the grid.
1431. Allegheny states that since generator operators do not have
the same resources as transmission operators for taking corrective
actions, the Commission's third proposed directive should be modified
to apply only to transmission operators. Allegheny states that while a
transmission operator can direct a generator operator to take specific
actions, the reverse is not the case.
1432. FirstEnergy contends that Requirement R2.1 essentially
requires generator operators to report all protective relay or
equipment failures, since generator operators may not be able to tell
which failures will reduce system reliability. FirstEnergy suggests
that R2.1 should be revised to require generator operators to report
all equipment failures or outages. FirstEnergy further suggests that
PRC-001-1 be revised to provide that if a company performs reasonable
testing procedures, undiscoverable equipment failures will not be
violations of R2.1.
1433. MidAmerican states that the term ``immediately'' in the
Commission's second directive is ambiguous and unenforceable. It
suggests a 30-minute time limit.
ii. Commission Determination
1434. The Commission approves PRC-001-1 as mandatory and
enforceable. We also direct NERC to develop a modification to PRC-001-1
through the Reliability Standards development process, as discussed
below.
1435. The Commission observes that, collectively, the comments
raise three general questions: (1) Whether relay or equipment failures
reduce system reliability and, if so, in what circumstances; (2) what
are ``corrective actions'' required to return a system to a secure
operating state and (3) when is returning a system to a secure
operating state ``as soon as possible.'' \379\ The Commission will
discuss each question in turn.
---------------------------------------------------------------------------
\379\ PRC-001-1 Requirement R2.2 provides: ``If a protective
relay or equipment failure reduces system reliability, the
Transmission Operator shall notify its Reliability Coordinator and
affected Transmission Operators and Balancing Authorities. The
Transmission Operator shall take corrective action as soon as
possible.''
---------------------------------------------------------------------------
(a) Whether Relay or Equipment Failures Reduce System Reliability and,
if So, in What Circumstances?
1436. Protection systems on Bulk-Power System elements are an
integral part of reliable operations. They are designed to detect and
isolate faulty elements on a power system, thereby limiting the
severity and spread of disturbances and preventing possible damage to
protected elements. If a protection system can no longer perform as
designed because of a failure of its relays, system reliability is
reduced or threatened. In deriving SOLs and IROLs, moreover, the
functions, settings, and limitations of protection systems are
recognized and integrated. Systems are only reliable when protection
systems perform as designed. This is what PRC-001-1 means in linking a
reduction in system reliability with a protection relay failure or
other equipment failure.
1437. With respect to MISO's comment that virtually all protection
systems have backups and therefore the Commission's proposals are not
necessary, unless the backup protection has the same design goals and
capabilities as the primary protection, a relay failure in the primary
protection may still threaten system reliability. Further, we note that
while the PRC Reliability Standards do not specifically require
protection systems consisting of redundant and independent protection
groups for each critical element in the Bulk-Power System, such
requirements are included as one potential solution in the TPL
Reliability Standards.\380\
---------------------------------------------------------------------------
\380\ If delayed clearing results in reliability criteria
violations, one solution can be the use of redundant relay systems.
TPL-002-0 Table 1, footnote e.
---------------------------------------------------------------------------
1438. Finally, MISO's question seems to imply that if there are
redundant relaying packages providing redundant protection, and a
problem develops with only one of those redundant packages, system
reliability is not threatened, and therefore, there is no need to take
corrective control actions within 30 minutes. We agree with MISO's
conclusion for this scenario.
1439. In the case, however, of a system element protected by a
single protection system with a failed relay that threatens system
reliability, that scenario would require the use of appropriate
operating solutions including removing a system element from service.
Another possible solution is to operate a system at a lower SOL or IROL
that recognizes the degraded protection performance.
(b) What Are Corrective Actions?
1440. Corrective actions taken by transmission operators to return
a system to a secure operating state when a protective relay or
equipment failure reduces system reliability normally refer to
``operator control actions'', consisting of operator actions such as
removing the facility without protection from service, generation
redispatch, transmission re-configuration, etc. Corrective action must
be completed as soon as possible, but no longer than 30 minutes after a
notice of protection system failure. Failure to complete corrective
action within 30 minutes will be considered a violation of the relevant
IROL or TOP Reliability Standards. In contrast, troubleshooting or
replacing failed relays or equipment are performed by field maintenance
personnel and normally take hours or even days to complete. These
actions are not normally considered corrective actions in the context
of real-time operation of the Bulk-Power System.
1441. We believe that ``[t]he transmission operator shall take
corrective action as soon as possible'' refers to transmission
operators taking operator control actions. It does not refer to
troubleshooting, repairing or replacing failed relays or equipment,
etc., since these time-consuming corrective actions would prolong the
risk of cascading failures to the Bulk-Power System.
1442. Dynegy, Wisconsin Electric and Northern Indiana are concerned
that the time required to troubleshoot, repair or replace failed relays
and equipment would be substantially longer than the 30 minutes set
forth in the Commission's proposed directive. We believe we have
alleviated this concern in our discussion, above. In addition, in
response to Northern Indiana, we clarify that the responsibility for
assessing whether a particular relay or protective system failure
reduces system reliability remains with transmission operators. We
direct the ERO to clarify the term
[[Page 16553]]
``corrective action'' consistent with this discussion when it modifies
PRC-001-1 in the Reliability Standards development process.
1443. We agree with Allegheny that generator operators do not have
the same ability as transmission operators to take corrective control
actions on the Bulk-Power System, and we will modify our third
directive as set forth below. We believe this also addresses Progress
Electricity Committee and California Cogeneration's similar concerns.
(c) When Is ``As Soon as Possible''?
1444. As explained above, the requirement for system operators to
take corrective control action when protective relay or equipment
failure reduces system reliability should be treated the same as the
requirement for returning a system to a secure and reliable state after
an IROL violation, i.e., as soon as possible, but no longer than 30
minutes after a violation. A longer time limit would place an entity in
violation of relevant IROL or TOP Reliability Standards.
1445. The Commission directs the ERO to consider FirstEnergy and
California PUC's comments about the maximum time for corrective action
in the ERO Reliability Standards development process.
1446. In response to MidAmerican's request that we clarify the term
``immediately'' in our proposed second directive, we direct the ERO, in
the Reliability Standards development process, to determine the
appropriate amount of time after the detection of relay failures, in
which relevant transmission operators must be informed of such
failures.
1447. We agree with APPA that the added Measures and Levels of Non-
Compliance incorrectly reference non-existent requirements. We direct
the ERO to revise the references accordingly.
1448. We disagree with APPA that BAL and IRO Reliability Standards
already address matters contained in PRC-001-1, because BAL and IRO are
not related to relay and equipment failures, which are specifically
addressed in PRC-001-1.
1449. We disagree with APPA's assertion that ``the Reliability
Standards on mitigating IROL violations are not specific enough and
system operators or field protection and control personnel would not be
alerted about failure of relays and protection systems on critical
elements.'' The time allowed for mitigating actual IROL violations is
very clear: as soon as possible and within 30 minutes. We clarify that
our concern is not about ``field protection and control personnel not
being alerted about failure of relays and protection systems on
critical elements.'' Our focus, rather, is that upon detection of
failure of relays and protection systems on critical elements, field
personnel must report the failures promptly to the transmission
operators so that corrective operator control actions can be taken as
soon as possible and within 30 minutes. Finally, with respect to APPA's
contention that our proposed directives would result in local-level
personnel undermining or not following the instructions of reliability
coordinator personnel at a time when the system is unstable, we do not
understand how local level personnel, who have no operating control of
a transmission operator's system or a reliability coordinator's system
could do so.
1450. The Commission approves Reliability Standard PRC-001-1 as
mandatory and enforceable. In addition, the Commission directs the ERO
to develop modifications to PRC-001-1 through the Reliability Standards
development process that: (1) Correct the references for Requirements
and (2) include a requirement that upon the detection of failures in
relays or protection system elements on the Bulk-Power System that
threaten reliable operation, relevant transmission operators must be
informed promptly, but within a specified period of time that is
developed in the Reliability Standards development process, whereas
generator operators must also promptly inform their transmission
operators and (3) clarifies that, after being informed of failures in
relays or protection system elements that threaten reliability of the
Bulk-Power System, transmission operators must carry out corrective
control actions, i.e., return a system to a stable state that respects
system requirements as soon as possible and no longer than 30 minutes
after they receive notice of the failure.
b. Define Regional Disturbance Monitoring and Reporting Requirements
(PRC-002-1)
1451. PRC-002-1 ensures that each regional reliability organization
establishes requirements to install Disturbance Monitoring Equipment
(DME) and report disturbance data to facilitate analyses of events and
verify system models.
1452. In the NOPR, the Commission identified PRC-002-1 as a fill-
in-the-blank standard. The NOPR stated that because the regional
requirements for installing DME had not been submitted, the Commission
would not approve or remand PRC-002-1 until the ERO submitted the
additional information.
i. Comments
1453. APPA agrees with the Commission's proposed course of action.
It states that there are significant and substantive differences
between regional procedures due to the characteristics of various
regional grids. Further it suggests that NERC and the Regional Entities
consider whether they can attain greater consistency on an
Interconnection-wide basis in addressing the completion of this
Reliability Standard.
1454. Alcoa suggests that the ERO--instead of a Regional Entity--
should define the requirements for DME and the type of report it
generates. The requirements and equipment specifications should be
consistent throughout North America. In addition, Alcoa suggests that
the criteria for installation of such equipment should include the
necessary monitoring and recording that contribute to analysis and
enhance reliability.
1455. Otter Tail suggests that PRC-002-1 should be developed on an
Interconnection-wide basis to ensure consistency and promote
reliability of the Bulk-Power System.
ii. Commission Determination
1456. For the reasons stated in the NOPR, the Commission will not
approve or remand PRC-002-1.
1457. We agree with APPA, Alcoa and Otter Tail that the ERO should
consider whether greater consistency can be achieved in this
Reliability Standard. In Order No. 672, the Commission also encouraged
greater uniformity in the development of Reliability Standards.\381\
Consistent with that goal, the Commission directs the ERO to consider
APPA, Alcoa and Otter Tail's suggestions in the Reliability Standards
development process as it modifies PRC-002-1 to provide missing
information needed for the Commission to act on this Reliability
Standard.
---------------------------------------------------------------------------
\381\ Order No. 672 at P 292.
---------------------------------------------------------------------------
c. Regional Procedure for Analysis of Misoperations of Transmission and
Generation Protection Systems (PRC-003-1)
1458. PRC-003-1 ensures that all transmission and generation
protection system misoperations are analyzed, and corrective action
plans are developed. Misoperations occur when a protection system
operates when it should not or does not operate when it should. This
Reliability Standard requires each regional reliability organization to
develop a procedure to monitor and review misoperations of protection
[[Page 16554]]
systems and to develop and document corrective actions.
1459. In the NOPR, the Commission identified PRC-003-1 as a fill-
in-the-blank standard. The NOPR stated that because the regional
procedures had not been submitted, the Commission proposed not to
approve or remand PRC-003-1 until the ERO submitted the additional
information.
i. Comments
1460. APPA agrees with the Commission's proposed course of action.
It states that there are significant and substantive differences
between regional procedures due to the characteristics of various
regional grids and industry structures. Further it suggests that NERC
and the Regional Entities consider whether they can attain greater
consistency on an Interconnection-wide basis in completing this
Reliability Standard.
ii. Commission Determination
1461. For the reasons stated in the NOPR, the Commission will not
approve or remand PRC-003-1.
1462. We agree with APPA that the ERO should consider whether
greater consistency can be achieved in this Reliability Standard. In
Order No. 672, the Commission also encouraged greater uniformity in the
development of Reliability Standards.\382\ Consistent with that goal,
the Commission directs the ERO to consider APPA's suggestions in the
Reliability Standards development process as it modifies PRC-003-1 to
provide missing information needed for the Commission to act on this
Reliability Standard.
---------------------------------------------------------------------------
\382\ Id. at P 292.
---------------------------------------------------------------------------
d. Analysis and Reporting of Transmission Protection System
Misoperations (PRC-004-1)
1463. PRC-004-1 ensures that all transmission and generation
protection system misoperations affecting the reliability of the Bulk-
Power System are analyzed and mitigated by requiring transmission
owners, generator owners and distribution providers that own a
transmission protection system to analyze and document protection
system misoperations. These entities must also develop corrective
action plans in accordance with the regional reliability organization's
procedures.
1464. In the NOPR, the Commission proposed to approve PRC-004-1 as
mandatory and enforceable.
i. Comments
1465. APPA agrees that PRC-004-1 is sufficient for approval as a
mandatory and enforceable Reliability Standard.
1466. ISO-NE and ISO/RTO Council oppose the Commission's proposed
approval of PRC-004-1 because it relies on PRC-003-1, a fill-in-the-
blank standard, which the Commission does not propose to approve or
remand until the ERO submits additional information.
1467. ISO-NE further requests the Commission to direct NERC to
modify PRC-004-1 to include LSEs and transmission operators in the
applicability section. It states that based on current practice in the
ISO-NE balancing area, transmission operators, transmission owners,
LSEs and distribution providers may individually or jointly own and
operate a protection system. It therefore suggests that transmission
operators and LSEs should also be included in the applicability
section. ISO-NE provides the same suggestion with regard to PRC-005-1,
PRC-008-0, PRC-011-0, PRC-015-0, PRC-016-0, PRC-017-0 and PRC-021-1.
ii. Commission Determination
1468. The Commission approves Reliability Standard PRC-004-1 as
mandatory and enforceable.
1469. We are not persuaded by ISO-NE and ISO/RTO Council's
assertion that PRC-004-1 should not be approved because it refers to
PRC-003-1, which is a fill-in-the-blank standard. In part, we neither
approve nor remand PRC-003-1 because it applies to a regional
reliability organization, and we are not persuaded that a regional
reliability organization's compliance with a Reliability Standard can
be enforced as NERC proposes.\383\ This is not the case with PRC-004-1,
which applies to transmission owners, distribution providers, and
generator owners. Since PRC-004-1 is an existing Reliability Standard
that has been followed on a voluntary basis, transmission owners,
distribution providers and generator owners are on notice of
requirements related to misoperations of transmission and generation
protection systems. As stated in the Common Issues section, a reference
to an unapproved Reliability Standard may be considered in an
enforcement action, but is not a reason to delay approving and
enforcing this Reliability Standard.
---------------------------------------------------------------------------
\383\ NOPR at P 56-57.
---------------------------------------------------------------------------
1470. We direct the ERO to consider ISO-NE's suggestion that LSEs
and transmission operators should be included in the applicability
section, in the Reliability Standards development process as it
modifies PRC-004-1.\384\ Further, as the ERO reviews this Reliability
Standard in its five-year cycle of review, the Regional Entity, rather
the regional reliability organization, should develop the procedures
for corrective action plans.
---------------------------------------------------------------------------
\384\ The same suggestion and therefore same Commission response
also applies to PRC-005-1, PRC-008-0, PRC-011-0, PRC-015-0, PRC-016-
0, PRC-017-0 and PRC-021-1.
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e. Transmission and Generation Protection System Maintenance and
Testing (PRC-005-1)
1471. PRC-005-1 ensures that all transmission and generation
protection systems affecting the reliability of the Bulk-Power System
are maintained and tested by requiring the transmission owners,
distribution providers, and generator owners to develop, document, and
implement a protection system maintenance program that may be reviewed
by the regional reliability organization.
1472. In the NOPR, the Commission proposed to approve PRC-005-1 as
mandatory and enforceable. In addition, the Commission proposed to
direct NERC to submit a modification to PRC-005-1 that includes a
requirement that maintenance and testing of a protection system must be
carried out within a maximum allowable interval that is appropriate to
the type of the protection system and its impact on the reliability of
the Bulk-Power System.
i. Comments
1473. FirstEnergy states that NERC should establish a maximum
maintenance interval for protection system equipment, and a national
limitation taking into account both relay type and functional versus
calibration testing. Entergy does not object to the development of
maximum allowable maintenance intervals provided that they are
developed in NERC's Reliability Standards development process.
1474. FirstEnergy and ISO-NE suggest that PRC-005-1, PRC-008-0,
PRC-011-0 and PRC-017-0 should be combined into a single Reliability
Standard relating to the maintenance of protection and control
equipment.
ii. Commission Determination
1475. For the reasons stated in the NOPR, the Commission approves
Reliability Standard PRC-005-1 as mandatory and enforceable.
1476. In addition, for the reasons discussed in the NOPR, the
Commission directs the ERO to develop a modification to PRC-005-1
through the
[[Page 16555]]
Reliability Standards development process that includes a requirement
that maintenance and testing of a protection system must be carried out
within a maximum allowable interval that is appropriate to the type of
the protection system and its impact on the reliability of the Bulk-
Power System. We further direct the ERO to consider FirstEnergy's and
ISO-NE's suggestion to combine PRC-005-1, PRC-008-0, PRC-011-0 and PRC-
017-0 into a single Reliability Standard through the Reliability
Standards development process.
f. Development and Documentation of Regional UFLS Programs (PRC-006-0)
1477. PRC-006-0 ensures the development of a regional UFLS \385\
program that will be used as a last resort to preserve the Bulk-Power
System during a major system failure that could cause system frequency
to collapse. PRC-006-0 requires the regional reliability organization
to develop, coordinate, document and assess UFLS program design and
effectiveness at least every five years.
---------------------------------------------------------------------------
\385\ Underfrequency load shedding.
---------------------------------------------------------------------------
1478. In the NOPR, the Commission identified PRC-006-0 as a fill-
in-the-blank standard. The NOPR stated that because the regional
procedures had not been submitted, the Commission would not propose to
approve or remand PRC-006-0 until the ERO submits the additional
information. The Commission commends the ERO and regions' initiative,
outlined in the Reliability Standards Work Plan, in adopting an
integrated and coordinated approach to protection for generators,
transmission lines and UFLS and UVLS \386\ programs as part of its work
on fill-in-the-blank Reliability Standards.\387\
---------------------------------------------------------------------------
\386\ Undervoltage load shedding.
\387\ NOPR at P 367.
---------------------------------------------------------------------------
i. Comments
1479. APPA agrees with the Commission's proposed course of action.
It suggests that in completing this Reliability Standard, NERC should
strive for greater consistency on an Interconnection-wide basis through
the use of ``base procedures'' for each Interconnection.
ii. Commission Determination
1480. For the reasons stated in the NOPR, the Commission will not
approve or remand PRC-006-0.
1481. The Commission understands that UFLS, when properly
coordinated with the dynamic response of the Bulk-Power System, is one
of the safety nets that safeguards the system from cascading events,
assuming it is properly coordinated with the dynamic response of the
system. Until this Reliability Standard is submitted to the Commission
for approval, we do not expect any lapse in the compliance with this
Reliability Standard. As we stated in the NOPR, it is important that
the existing regional reliability organizations continue to fulfill
their current roles during this time of transition. The Commission
expects that this function will pass from the regional reliability
organization to the Regional Entity after they are approved.
g. Assuring Consistency With Regional UFLS Program Requirements (PRC-
007-0)
1482. PRC-007-0 requires transmission owners, transmission
operators, LSEs and distribution providers to provide, and annually
update, their underfrequency data to facilitate the regional
reliability organization's maintenance of the UFLS program database.
1483. In the NOPR, the Commission proposed to approve PRC-007-0 as
mandatory and enforceable.
i. Comments
1484. APPA agrees that PRC-007-0 is sufficient for approval as a
mandatory and enforceable Reliability Standard. However, it states that
actual enforcement cannot take place until PRC-006-0 becomes effective.
ISO-NE and ISO/RTO Council state that PRC-007-0 should not be approved
because it refers to PRC-006-0, which we are not approving or remanding
at this time.
ii. Commission Determination
1485. For the reasons stated in the NOPR, the Commission approves
Reliability Standard PRC-007-0 as mandatory and enforceable.
1486. We are not persuaded by APPA, ISO/RTO Council and ISO-NE that
PRC-007-0 cannot be acted on because it relies on PRC-006-0. We
proposed to not approve or remand PRC-006-0 partly because it applies
to a regional reliability organization. The Commission was not
persuaded that a regional reliability organization's compliance with a
Reliability Standard can be enforced as NERC proposed.\388\ That is not
the case with PRC-007-0, which applies to transmission owners,
transmission operators, distribution providers and LSEs. Since PRC-007-
0 is an existing Reliability Standard that has been followed on a
voluntary basis, transmission owners, transmission operators,
distribution providers and LSEs are generally aware of its
requirements. As stated in the Common Issues section, a reference to an
unapproved Reliability Standard may be considered in an enforcement
action, but is not a reason to delay approving and enforcing this
Reliability Standard. The Commission expects that the data will be sent
to the Regional Entities (instead of the regional reliability
organizations) after they are approved.
---------------------------------------------------------------------------
\388\ NOPR at P 56-57.
---------------------------------------------------------------------------
h. Underfrequency Load Shedding Equipment Maintenance Programs (PRC-
008-0)
1487. PRC-008-0 requires transmission owners and distribution
providers to implement UFLS equipment maintenance and testing programs
and provide program results to the regional reliability organization.
1488. In the NOPR, the Commission proposed to approve Reliability
Standard PRC-008-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to PRC-008-
0 that includes a requirement that maintenance and testing of UFLS
programs must be carried out within a maximum allowable interval
appropriate to the relay type and the potential impact on the Bulk-
Power System.
i. Comments
1489. Entergy states that it does not object to NERC's development
of maximum allowable maintenance intervals for the purpose of
evaluating protection system and control programs provided that they
are developed in NERC's Reliability Standards development process.
FirstEnergy states that NERC should establish a maximum maintenance
interval for protection system equipment and a ``national limitation
taking into account both relay type and functional versus calibration
testing.''
1490. ISO-NE and ISO/RTO Council contend that the Commission should
not approve PRC-008-0 until it approves PRC-006-0, which the Commission
has identified as a fill-in-the-blank standard. Similarly, APPA
contends that PRC-008-0 cannot be enforced until PRC-006-0 has become
effective and the required regional UFLS program documentation has been
submitted by the applicable Regional Entity. It also notes that the
applicability of PRC-008-0 is limited to transmission owners and
distribution providers who are required by their regional reliability
organization to have a UFLS program.
[[Page 16556]]
ii. Commission Determination
1491. FirstEnergy and Entergy agree with the Commission's proposed
directive, whereas APPA suggests that the need for the proposal should
be established first via the Reliability Standards development process.
1492. We disagree with ISO/RTO Council and others that approval or
enforcement of PRC-008-0 is linked to approval of PRC-006-0. PRC-008-0
requires that a ``transmission provider or distribution provider with a
UFLS program (as required by its Regional Reliability Organization)
shall have a UFLS equipment and maintenance testing program in place.''
\389\ PRC-006-0 requires each regional reliability organization to
develop, coordinate and document a UFLS program that includes specified
elements. Again, we proposed to neither approve nor remand PRC-006-0
because it applies to a regional reliability organization and the
Commission was not persuaded that a regional reliability organization's
compliance with a Reliability Standard can be enforced as proposed by
NERC.\390\ That is not the case with PRC-008-0, which applies to
transmission owners and distribution providers. Since PRC-008-0 is an
existing Reliability Standard that has been followed on a voluntary
basis, transmission owners and distribution providers are aware whether
they are required to have a UFLS program in place. We approve PRC-008-0
as mandatory and enforceable because it requires entities to have
equipment maintenance and testing of their UFLS programs. As stated in
the Common Issues section, a reference to an unapproved Reliability
Standard may be considered in an enforcement action, but is not a
reason to delay approving and enforcing this Reliability Standard. The
Commission expects that the program results will be sent to the
Regional Entities (instead of the regional reliability organizations)
after they are approved.
---------------------------------------------------------------------------
\389\ See PRC-008-0, Requirement R1.
\390\ NOPR at P 56-57.
---------------------------------------------------------------------------
1493. The Commission approves Reliability Standard PRC-008-0 as
mandatory and enforceable. In addition, the Commission directs the ERO
to develop a modification to PRC-008-0 through the Reliability
Standards development process that includes a requirement that
maintenance and testing of a protection system must be carried out
within a maximum allowable interval that is appropriate to the type of
the protection system and its impact on the reliability of the Bulk-
Power System.
i. UFLS Performance Following an Underfrequency Event (PRC-009-0)
1494. PRC-009-0 ensures that the performance of a UFLS system is
analyzed and documented following an underfrequency event by requiring
the transmission owner, transmission operator, LSE and distribution
provider to document the deployment of their UFLS systems in accordance
with the regional reliability organization's program.
1495. In the NOPR, the Commission proposed to approve Reliability
Standard PRC-009-0 as mandatory and enforceable.
i. Comments
1496. APPA agrees that PRC-009-0 is sufficient for approval as a
mandatory and enforceable Reliability Standard. However, it states that
actual enforcement cannot take place until pending PRC-006-0 becomes
effective and notes that the applicability of PRC-009-0 is limited to
entities that own or operate a UFLS program recognized by their
regional reliability organization.
1497. ISO-NE and ISO/RTO Council contend that the Commission should
not approve PRC-009-0 until it approves PRC-006-0, which the Commission
has identified as a fill-in-the-blank standard.
ii. Commission Determination
1498. For the reasons stated in the NOPR, the Commission approves
Reliability Standard PRC-009-0 as mandatory and enforceable.\391\
---------------------------------------------------------------------------
\391\ NOPR at P 877-80.
---------------------------------------------------------------------------
1499. We disagree with ISO/RTO Council and others that approval or
enforcement of PRC-009-0 is linked to approval of PRC-006-0. PRC-009-0
ensures that the performance of a UFLS system is analyzed and
documented following an underfrequency event by requiring the
transmission owner, transmission operator, LSE, and distribution
provider to document the deployment of their UFLS operations. PRC-006-0
requires each regional reliability organization to develop, coordinate
and document a UFLS program that includes specified elements. We
proposed to neither approve nor remand PRC-006-0 because it applies to
a regional reliability organization and the Commission was not
persuaded that a regional reliability organization's compliance with a
Reliability Standard can be enforced as NERC proposed.\392\ That is not
the case with PRC-009-0, which applies to transmission owners,
transmission operators, LSEs and distribution providers with UFLS
systems. Since PRC-009-0 is an existing Reliability Standard that has
been followed on a voluntary basis, entities are aware whether they are
required to have a UFLS program in place. Reporting on their UFLS
programs therefore should not be burdensome. As stated in the Common
Issues section, a reference to an unapproved Reliability Standard may
be considered in an enforcement action, but is not a reason to delay
approving and enforcing this Reliability Standard. The Commission
expects this documentation will be sent to the Regional Entities
(instead of the regional reliability organizations) after they are
approved.
---------------------------------------------------------------------------
\392\ NOPR at P 56-57.
---------------------------------------------------------------------------
j. Assessment of the Design and Effectiveness of UVLS Program (PRC-010-
0)
1500. PRC-010-0 requires transmission owners, transmission
operators, LSEs and distribution providers to periodically conduct and
document an assessment of the effectiveness of their UVLS program at
least every five years or as required by changes in system conditions.
The assessment must be conducted with the associated transmission
planner and planning authority.
1501. In the NOPR, the Commission proposed to approve Reliability
Standard PRC-010-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to PRC-010-
0 that requires that an integrated and coordinated approach be included
in all protection systems on the Bulk-Power System, including
generators and transmission lines, generators' low voltage ride-through
capabilities and UFLS and UVLS programs.
1502. The Commission commends the initiative and efforts that have
been taken by NERC and the industry in addressing UVLS requirements as
recommended by the Blackout Report.
i. Comments
1503. APPA agrees that PRC-010-0 should be approved. While APPA
agrees and that NERC should re-examine this Reliability Standard to
determine whether a more integrated and coordinated approach should be
included in protection systems on the Bulk-Power System, it also asks
the Commission not to require a specific approach to UVLS and other
protection systems. According to APPA, NERC should strive for greater
consistency on an Interconnection-wide basis through
[[Page 16557]]
the use of a coordinated protection system for the Bulk-Power System in
each Interconnection.
1504. ISO-NE generally supports approval of PRC-010-0, but opposes
the Commission's directive to modify the Reliability Standard to
include an integrated and coordinated approach in all protection
systems, particularly for UVLS and UFLS, programs, because such
integration cannot be technologically accomplished.
1505. FirstEnergy indicates that UVLS is primarily designed to
address localized problems, and therefore requiring the universal
coordination of UVLS across the grid does not make sense. FirstEnergy
states that it is not clear what type of coordination would be useful
for a UVLS program.
ii. Commission Determination
1506. We agree with APPA's comments and reiterate that the directed
modification should be developed in the Reliability Standards
development process. With regard to APPA's concerns, while we direct
the ERO to develop modifications that would require an integrated and
coordinated approach to protection systems, we do not direct a specific
approach to accomplish such integration and coordination. Rather, the
ERO should develop an appropriate approach utilizing the Reliability
Standards development process.
1507. With regard to ISO-NE's disagreement on integration of
various system protections ``because such integration cannot be
technologically accomplished'', we note that the evidence collected in
the Blackout Report indicates that ``the relay protection settings for
the transmission lines, generators and underfrequency load shedding in
the northeast may not be entirely appropriate and are certainly not
coordinated and integrated to reduce the likelihood and consequence of
a cascade--nor were they intended to do so.'' In addition, the Blackout
Report stated that one of the common causes of major outages in North
America is a lack of coordination on system protection. The Commission
agrees with the protection experts who participated in the
investigation, formulated Blackout Recommendation No. 21 and
recommended that UVLS programs have an integrated approach.\393\
---------------------------------------------------------------------------
\393\ ``Recommend that NERC determine the goal and principles
needed to establish an integrated approach to relay protection for
generators and transmission lines and the use of underfrequency and
undervoltage load shedding programs.'' Blackout Report at 159.
---------------------------------------------------------------------------
1508. Regarding FirstEnergy's question of whether universal
coordination among UVLS programs that address local system problems
makes sense, we believe that PRC-010-0's objective in requiring an
integrated and coordinated approach is to address the possible adverse
interactions of these protection systems among themselves and to
determine whether they could aggravate or accelerate cascading events.
We do not believe this Reliability Standard is aimed at universal
coordination among UVLS programs that address local system problems.
1509. As identified in the NOPR,\394\ NERC is continuing to develop
an integrated and coordinated approach to protection for generators,
transmission lines and UFLS and UVLS programs within its work on the
fill-in-the-blank proposed Reliability Standards.
---------------------------------------------------------------------------
\394\ NOPR P 883.
---------------------------------------------------------------------------
1510. We appreciate MEAG's feedback to our response in the NOPR.
For the reasons discussed in the NOPR,\395\ as well as our explanation
above, the Commission approves Reliability Standard PRC-010-0 as
mandatory and enforceable. In addition, the Commission directs the ERO
to develop a modification to PRC-010-0 through the Reliability
Standards development process that requires that an integrated and
coordinated approach be included in all protection systems on the Bulk-
Power System, including generators and transmission lines, generators'
low voltage ride-through capabilities, and UFLS and UVLS programs.
---------------------------------------------------------------------------
\395\ Id. P 891-92.
---------------------------------------------------------------------------
k. UVLS System Maintenance and Testing (PRC-011-0)
1511. PRC-011-0 requires transmission owners and distribution
providers to implement their UVLS equipment maintenance and testing
programs and provide program results to regional reliability
organizations.
1512. In the NOPR, the Commission proposed to approve PRC-011-0 as
mandatory and enforceable. In addition, the Commission proposed to
direct NERC to submit a modification to PRC-011-0 that includes a
requirement that maintenance and testing of UVLS programs must be
carried out within a maximum allowable interval appropriate to the
relay type and the potential impact on the Bulk-Power System.
i. Comments
1513. APPA suggests that, instead of a Commission directive, NERC
should be directed to consider whether this standard is needed to
address the Commission's concern about periodic testing of UVLS
equipment.
1514. FirstEnergy comments that NERC should establish a maximum
maintenance interval for protection system equipment, and a ``national
limitation taking into account both relay type and functional versus
calibration testing.'' Entergy states that it does not object to NERC's
development of maximum allowable maintenance intervals for the purpose
of evaluating protection system and control programs.
ii. Commission Determination
1515. The Commission approves Reliability Standard PRC-011-0 as
mandatory and enforceable. In addition, we direct the ERO to develop
modifications to the Reliability Standard through the Reliability
Standards development process as discussed below.
1516. The Commission disagrees with APPA that the decision whether
a modification is needed should be established first by the ERO in its
Reliability Standards development process. Our direction identifies an
appropriate goal necessary to assure the reliable operation of the
Bulk-Power System. The details should be developed through the
Reliability Standards development process.
1517. The Commission believes that the proposal is presently part
of the process. The Commission approves Reliability Standard PRC-011-0
as mandatory and enforceable. In addition, the Commission directs the
ERO to submit a modification to PRC-011-0 through the Reliability
Standards development process that includes a requirement that
maintenance and testing of a protection system must be carried out
within a maximum allowable interval that is appropriate to the type of
the protection system and its impact on the reliability of the Bulk-
Power System.
l. Special Protection System Review Procedure (PRC-012-0)
1518. PRC-012-0 requires regional reliability organizations to
ensure that all special protection systems \396\ are properly designed,
meet performance requirements and are coordinated with other protection
systems.
---------------------------------------------------------------------------
\396\ A special protection system is designed to automatically
take corrective actions to protect a particular system under both
abnormal and predetermined conditions, excluding the coordinated
tripping of circuit breakers to isolate faulted components, which is
typically the purpose of other protection devices.
---------------------------------------------------------------------------
In the NOPR, the Commission identified PRC-012-0 as a fill-in-the-
blank standard. The NOPR stated that
[[Page 16558]]
because the regional review procedures on special protection systems
have not been submitted, the Commission would not propose to approve or
remand PRC-012-0 until the ERO submits the additional information.
i. Comments
1520. APPA agrees with the Commission's proposed course of action.
It further suggests that NERC, in completing PRC-012-0, should strive
for greater consistency on an Interconnection-wide basis through the
use of ``base procedures'' for each Interconnection.
ii. Commission Determination
1521. For the reasons stated in the NOPR, the Commission will not
approve or remand PRC-012-0. The Commission urges the ERO should
consider APPA's suggestions in the Reliability Standards development
process.
m. Special Protection System Database (PRC-013-0)
1522. PRC-013-0 ensures that all special protection systems are
properly designed, meet performance requirements and are coordinated
with other protection systems by requiring the regional reliability
organization to maintain a database of information on special
protection systems.
1523. In the NOPR, the Commission identified PRC-013-0 as a fill-
in-the-blank standard. The NOPR stated that because the regional
procedures on maintaining special protection system databases have not
been submitted, the Commission would not approve or remand PRC-013-0
until the ERO submits the additional information.
i. Comments
1524. APPA agrees with the Commission's proposed course of action.
It suggests further that in completing PRC-013-0, NERC should strive
for greater consistency on an Interconnection-wide basis through the
use of ``base procedures'' for each Interconnection.
ii. Commission Determination
1525. For the reasons stated in the NOPR, the Commission will not
approve or remand PRC-013-0. The ERO should consider APPA's suggestions
in the Reliability Standards development process.
n. Special Protection System Assessment (PRC-014-0)
1526. PRC-014-0 ensures that special protection systems are
properly designed, meet performance requirements and are coordinated
with other protection systems by requiring the regional reliability
organization to assess and document the operation, coordination and
compliance with NERC Reliability Standards and effectiveness of special
protection systems at least once every five years.
1527. In the NOPR, the Commission identified PRC-014-0 as a fill-
in-the-blank Reliability Standard. The NOPR stated that because the
regional procedures on special protection system assessment had not
been submitted, the Commission would not propose to approve or remand
PRC-014-0 until the ERO submitted the additional information.
i. Comments
1528. APPA agrees with the Commission's proposed course of action.
It suggests further that in completing PRC-014-0, NERC should strive
for greater consistency on an Interconnection-wide basis through the
use of ``base procedures'' for each Interconnection.
ii. Commission Determination
1529. For the reasons stated in the NOPR, the Commission will not
approve or remand PRC-014-0. The ERO should consider APPA's suggestions
in the Reliability Standards development process.
o. Special Protection System Data and Documentation (PRC-015-0)
1530. Proposed Reliability Standard PRC-015-0 requires transmission
owners, generator owners and distribution providers to maintain a
listing, retain evidence of review and provide documentation of
existing, new or functionally modified special protection systems.
1531. In the NOPR, the Commission proposed to approve PRC-015-0 as
mandatory and enforceable.
i. Comments
1532. APPA agrees that PRC-015-0 is sufficient for approval as a
mandatory Reliability Standard. However, it states that this
Reliability Standard cannot be enforced until two pending Reliability
Standards, PRC-012-0 and PRC-013-0, become effective. Similarly, ISO/
RTO Council and ISO-NE contend that the Commission should not approve
PRC-15-0 until it approves PRC-012-0 and PRC-013-0, identified by the
Commission as fill-in-the-blank standards.
ii. Commission Determination
1533. We disagree with APPA, ISO/RTO Council and ISO-NE and
conclude that PRC-015-0 should be approved and made enforceable on the
effective date of this rulemaking. As mentioned above, PRC-012-0 and
PRC-013-0 apply solely to regional reliability organizations. PRC-012
is ``process'' oriented, as it requires the regional reliability
organization to develop a review procedure that identifies information
relevant to the regional reliability organization review of a special
protection system. PRC-013-0 requires the regional reliability
organization to maintain a database of information on special
protection systems. PRC-015-0 requires a transmission owner, generator
owner or distribution provider that owns a special protection system to
maintain a list and provide data for existing and planned special
protection systems as defined in PRC-013-0; and have evidence that the
entity reviewed new or functionally modified special protection systems
in accordance with the regional reliability organization procedures
identified in PRC-012-0. As stated in the Common Issues section, a
reference to an unapproved Reliability Standard may be considered in an
enforcement action, but is not a reason to delay approving and
enforcing this Reliability Standard. The Commission expects that the
data will be sent to the Regional Entities (instead of the regional
reliability organizations) after they are approved.
1534. For the reasons discussed in the NOPR and above, the
Commission concludes that Reliability Standard PRC-015-0 is just,
reasonable, not unduly discriminatory or preferential and in the public
interest and approves it as mandatory and enforceable.
p. Special Protection System Misoperations (PRC-016-0)
1535. PRC-016-0 requires transmission owners, generator owners and
distribution providers to provide the regional reliability organization
with documentation, analyses and corrective action plans for
misoperation of special protection systems.
1536. In the NOPR, the Commission proposed to approve Reliability
Standard PRC-016-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to PRC-016-
0 that includes a requirement that maintenance and testing of these
special protection system programs be carried out within a maximum
allowable interval that is appropriate for the type of relays used and
the impact of these special system protection systems on the
reliability of the Bulk-Power System.
[[Page 16559]]
i. Comments
1537. While APPA agrees that PRC-016-0 is sufficient for approval
as a mandatory Reliability Standard, APPA, ISO/RTO Council and ISO-NE
state that PRC-016-0 cannot be enforced until pending Reliability
Standard PRC-012-0 has become effective.
1538. FirstEnergy suggests that NERC clarify and provide guidance
to transmission operators on the types of misoperations that have
Interconnection-wide impacts and the types of misoperations that need
reporting.
ii. Commission Determination
1539. PRC-016-0 states that transmission owners, generator owners
and distribution providers that own a special protection system must
analyze the system operations and maintain a record of misoperations in
accordance with the review procedure specified in PRC-012-0. As we
explained above in the context of PRC-015-0, applicable entities are
expected to comply with PRC-015-0, and the procedures specified in PRC-
012-0 will continue to be maintained by the regional reliability
organizations pursuant to the ERO Rules of Procedure and the
Commission's reliability information provision. We disagree with APPA,
ISO/RTO Council and ISO-NE and conclude that PRC-016-0 is enforceable
as of the effective date of this rulemaking. As stated in the Common
Issues section, a reference to an unapproved Reliability Standard may
be considered in an enforcement action, but is not a reason to delay
approving and enforcing this Reliability Standard. The Commission
expects that the plans will be sent to the Regional Entities (instead
of the regional reliability organizations) after they are approved.
1540. The Commission concludes that Reliability Standard PRC-016-0
is just, reasonable, not unduly discriminatory or preferential, and in
the public interest, and approves it as mandatory and enforceable. We
observe that a maximum allowable interval for maintenance and testing
of special protection systems is not relevant to PRC-016-0, where the
primary purpose is to analyze and report all misoperations of special
protection systems. The Commission, therefore, will not adopt the
proposal to require the ERO to modify PRC-016-0 to include a
requirement for a maximum allowable interval for maintenance and
testing.
1541. The Commission concludes that Reliability Standard PRC-016-0
is just, reasonable, not unduly discriminatory or preferential and in
the public interest, and approves it as mandatory and enforceable.
q. Special Protection System Maintenance and Testing (PRC-017-0)
1542. PRC-017-0 requires transmission owners, generator owners and
distribution providers to provide the regional reliability organization
with documentation of special protection system maintenance, testing
and implementation plans.
1543. In the NOPR, the Commission proposed to approve PRC-017-0 as
mandatory and enforceable. In addition, the Commission proposed to
direct NERC to submit a modification to PRC-017-0 that: (1) Includes a
requirement that maintenance and testing of these special protection
system programs must be carried out within a maximum allowable interval
that is appropriate to the type of relaying used and (2) identifies the
impact of these special protection system programs on the reliability
of the Bulk-Power System.
i. Comments
1544. APPA agrees that PRC-017-0 is sufficient for approval as a
mandatory and enforceable Reliability Standard. It also agrees that
NERC and the industry should consider adoption of maximum allowable
maintenance intervals. With respect to the Commission's second
directive, APPA points out that the documentation of the test results
will identify the impact of the special protection systems on the Bulk
Electric System.
1545. FirstEnergy states that NERC should establish a maximum
maintenance interval for protective system equipment and a national
limitation, taking into account both relay type and functional versus
calibration testing. Entergy does not object to NERC's development of
maximum allowable maintenance intervals for the purpose of evaluating
protection system and control programs.
ii. Commission Determination
1546. The commenters agree with the Commission's proposed directive
on a maximum allowable interval for maintenance and testing of
protection system equipment and we conclude that such a modification is
beneficial. However, we agree with APPA's view on our second proposed
directive assuming that the documentation is requested by either the
regional reliability organization or NERC. Therefore, we will modify
our direction to require that the documentation be routinely provided
to the ERO or Regional Entity and not only when it is requested.
1547. The Commission approves Reliability Standard PRC-017-0 as
mandatory and enforceable. In addition, the Commission directs the ERO
to develop a modification to PRC-017-0 through the Reliability
Standards development process, that includes: (1) a requirement that
maintenance and testing of a protection system must be carried out
within a maximum allowable interval that is appropriate for the type of
the protection system and (2) a requirement that documentation
identified in Requirement R2 shall be routinely provided to the ERO or
Regional Entity.
r. Disturbance Monitoring Equipment Installation and Data Reporting
(PRC-018-1)
1548. PRC-018-1 ensures that disturbance monitoring equipment is
installed and disturbance data is reported in accordance with
comprehensive requirements. PRC-018-1 contains several different
effective dates for specific requirements.
1549. In the NOPR, the Commission proposed to approve PRC-018-1 as
mandatory and enforceable.
i. Comments
1550. While APPA agrees that PRC-018-1 is sufficient for approval
as a mandatory Reliability Standard, it contends that enforcement is
not possible until PRC-002-0, a fill-in-the-blank standard, is
effective. For the same reason, ISO/RTO Council and ISO-NE state that
the Reliability Standard should not be approved or remanded at this
time.
ii. Commission Determination
1551. The portion of PRC-018-1 that NERC proposes will become
effective on the effective date of this Final Rule states that
transmission owners and generator owners that own a disturbance
monitoring system must assure that disturbance data is reported in
accordance with PRC-002-1 to facilitate analyses of events. Applicable
entities are expected to comply with PRC-018-1, and the procedures
specified in PRC-002-1 will be provided pursuant to the data gathering
provisions of the ERO's Rules of Procedure and the Commission's ability
to obtain information pursuant to section 215 of the FPA and Part 39 of
the Commission's regulations. Accordingly, we disagree with ISO/RTO
Council and ISO-NE and conclude that the effective portions of PRC-018-
1 are enforceable as of the effective date of this rulemaking. As
stated in the Common Issues section, a reference to an unapproved
Reliability Standard may be
[[Page 16560]]
considered in an enforcement action, but is not a reason to delay
approving and enforcing this Reliability Standard.
1552. Accordingly, for reasons stated in the NOPR and above, the
Commission approves Reliability Standard PRC-018-1 as mandatory and
enforceable.
s. Undervoltage Load Shedding Program Database (PRC-020-1)
1553. PRC-020-1 ensures that a regional database for UVLS programs
is available for Bulk-Power System studies by requiring regional
reliability organizations with any entities that have UVLS programs to
maintain and annually update a database.
1554. In the NOPR, the Commission identified PRC-020-1 as a fill-
in-the-blank standard. The NOPR stated that because the regional
procedures on maintaining UVLS databases have not been submitted, the
Commission would not propose to approve or remand PRC-020-0 until the
ERO submits the additional information.
i. Comments
1555. APPA disagrees that PRC-020-1 is a regional fill-in-the-blank
Reliability Standard because it does not require regional procedures.
However, APPA recognizes that PRC-020-1 requires the regional
reliability organization to establish a database.
ii. Commission Determination
1556. APPA is correct that the reason for not approving or
remanding this Reliability Standard is because it applies solely to the
regional reliability organization, and not because it is a fill-in-the-
blank standard. For this reason, the Commission will not approve or
remand PRC-020-1.
t. Undervoltage Load Shedding Program Data (PRC-021-1)
1557. PRC-021-1 ensures that data is supplied to support the
regional UVLS database by requiring the transmission owner and
distribution provider to supply data related to their systems and other
related protection schemes to their regional reliability organization's
database.
1558. In the NOPR, the Commission proposed to approve PRC-021-1 as
mandatory and enforceable.
i. Comments
1559. APPA agrees that PRC-021-1 should be approved as a mandatory
and enforceable Reliability Standard.
1560. The ISO-NE and ISO/RTO Council contend that the Commission
should refrain from approving PRC-021-1 until it approves PRC-020-1
which the Commission has not approved or remanded.
ii. Commission Determination
1561. For the reasons stated in the NOPR and above, the Commission
approves PRC-021-1 as mandatory and enforceable. The referenced
information will be provided pursuant to the data gathering provisions
of the ERO's rules of procedure and the Commission's ability to obtain
information pursuant to section 215 of the FPA and Part 39 of the
Commission's regulations. As stated in the Common Issues section, a
reference to an unapproved Reliability Standard may be considered in an
enforcement action, but is not a reason to delay approving and
enforcing this Reliability Standard.
u. Undervoltage Load Shedding Program Performance (PRC-022-1)
1562. PRC-022-1 requires transmission operators, LSEs, and
distribution providers to provide analysis, documentation and
misoperation data on UVLS operations to the regional reliability
organization.
1563. In the NOPR, the Commission proposed to approve PRC-022-1 as
mandatory and enforceable.
i. Comments
1564. APPA agrees that PRC-022-1 should be approved as a mandatory
and enforceable Reliability Standard.
1565. FirstEnergy comments that Requirement R1.3 requires ``a
simulation of the event, if deemed appropriate by the RRO'' and
believes that the applicable entities such as transmission operators
may not be able to simulate large system events. FirstEnergy suggests
that Requirement R1.3 be revised to state that ``a simulation of the
event, if deemed appropriate, and assisted by the [regional reliability
organization].''
ii. Commission Determination
1566. For the reasons discussed in the NOPR, the Commission
concludes that Reliability Standard PRC-022-1 is just, reasonable, not
unduly discriminatory or preferential, and in the public interest and
approves it as mandatory and enforceable.
1567. The Commission directs the ERO to consider FirstEnergy's
suggestion in the Reliability Standards development process.
11. TOP: Transmission Operations
1568. The eight Transmission Operations (TOP) Reliability Standards
apply to transmission operators, generator operators and balancing
authorities. The goal of these Reliability Standards is to ensure that
the transmission system is operated within operating limits.
Specifically, these Reliability Standards cover the responsibilities
and decision-making authority for reliable operations, requirements for
operations planning, planned outage coordination, real-time operations,
provision of operating data, monitoring of system conditions, reporting
of operating limit violations and actions to mitigate such violations.
The Interconnection Reliability Operations and Coordination (IRO) group
of Reliability Standards complement these proposed TOP Reliability
Standards.
a. Reliability Responsibilities and Authorities (TOP-001-1)
1569. The reliability goal of TOP-001-1 is to ensure that system
operators have the authority to take actions and direct others to take
action to maintain Bulk-Power System facilities within operating
limits. TOP-001-1 requires that: (a) Transmission operating personnel
must have the authority to direct actions in real-time; (b) the
transmission operator, balancing authority, and generator operator must
follow the directives of their reliability coordinator and (c) the
balancing authority and generator operator must follow the directives
of the transmission operator. In addition, the proposed Reliability
Standard requires the transmission operator, balancing authority,
generator operator, distribution provider and LSE to take emergency
actions when directed to do so in order to keep the transmission system
intact.
1570. The Commission proposed in the NOPR to approve the
Reliability Standard as mandatory and enforceable and to direct NERC to
submit a modification to it that includes Measures and Levels of Non-
Compliance. On November 15, 2006, NERC submitted revisions to the
Reliability Standard to include Measures and Levels of Non-
Compliance.\397\
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\397\ In its November 15, 2006, filing, NERC submitted TOP-001-
1, which supercedes the Version 0 Reliability Standard. TOP-001-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, TOP-001-1.
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i. Comments
1571. APPA notes that TOP-001-1, as revised to include Measures and
Levels of Non-Compliance, fulfills the proposed directive in the NOPR.
Accordingly, APPA agrees that the Commission should approve TOP-001-1
as mandatory and enforceable.
[[Page 16561]]
1572. California PUC asserts that TOP-001 should not be adopted
unless the Commission provides for proper deference to existing
authorities. It states that the requirements contained in TOP-001 are
duplicative of what the CAISO already requires under its participating
generator agreements.
1573. FirstEnergy contends that TOP-001-1 contains ``reliability
directives'' to be followed by various entities, but it has no clear
line of authority for specified directives. This could lead to a
generator receiving conflicting directions. FirstEnergy maintains that
TOP-001-1 should establish a clear line of authority for issuing and
complying with directives, but the reliability coordinator's
instructions should govern in all instances.
1574. In a similar vein, MEAG Power is concerned that the scope of
``reliability directives'' contained in the Measures filed on November
15, 2006 is unclear. For example, Measure M4 states that ``[e]ach
Balancing Authority, Generator Operator, Distribution Provider and Load
Serving Entity shall have and provide upon request evidence that * * *
it complied with its Transmission Operator's reliability directives.''
While a directive by a transmission operator to a LSE to increase its
planning reserve margin from 15 percent to 20 percent or reconductor a
transmission line might be within the realm of possibilities, such
``reliability directives'' would be inappropriate. MEAG Power therefore
recommends an alternative definition of ``reliability directive'' that
it believes would specify an appropriate range of directives.
1575. MEAG Power also recommends a modification to TOP-001-1
clarifying that an entity may be found non-compliant only if it fails
to comply with a reliability directive issued to it by its host
reliability coordinator. MEAG Power is concerned that the requirements
as currently written may apply to entities outside a reliability
coordinator's footprint.
1576. FirstEnergy and California Cogeneration state that the
definition of ``emergency'' is vague and should be clarified.
FirstEnergy states TOP-001 does not specify who decides when there is
an emergency. California Cogeneration states that under emergency
conditions, it would be appropriate to require a QF to follow the
directives of a reliability coordinator.\398\ But California
Cogeneration argues that because of the broad definition of emergency,
reliability coordinators could issue directives on a regular basis.
California Cogeneration therefore proposes that the Reliability
Standard clearly address which entities are exempt from such directives
because they have no material impact on reliability.
---------------------------------------------------------------------------
\398\ California Cogeneration notes that the curtailment of QFs
in an emergency is allowed by 18 CFR 292.307.
---------------------------------------------------------------------------
1577. FirstEnergy states that the term ``safety'' in Requirement R4
should be clarified with respect to whether it means safety to the
system/equipment, public safety or both.
1578. Requirement R6 of TOP-001-1 requires an applicable entity to
``render all available emergency assistance to others as requested.''
Regarding this provision, FirstEnergy maintains that NERC should
clarify that all instructions should be subject to the reliability
coordinator's direction and control to avoid causing unforeseen harm to
other systems. Any entity requesting assistance must implement its
emergency procedures before or in unison with assistance from other
entities. However, FirstEnergy asserts that it is not clear how a
responding entity will determine whether the requesting entity has
implemented its comparable emergency procedures before the responding
entity honors the request. FirstEnergy, therefore, states that TOP-001-
1 should require the requesting party to report on whether all of its
emergency procedures were implemented as part of its request for
emergency assistance.
1579. Santa Clara states that, in some instances, notifying the
reliability coordinator that a transmission operator is removing
facilities from service may not be appropriate because the transmission
owner traditionally notifies the balancing authority. Santa Clara
therefore requests that Requirements R7.2 and R7.3 of the Reliability
Standard be revised to provide that the transmission operator may
notify the reliability coordinator or balancing authority.\399\
---------------------------------------------------------------------------
\399\ Santa Clara makes a similar argument reagarding
Requirement R3 of TOP-008-1.
---------------------------------------------------------------------------
ii. Commission Determination
1580. The Commission approves TOP-001-1 as mandatory and
enforceable. We address the concerns raised by commenters below.
1581. While the Commission agrees with APPA that TOP-001-1 should
be approved, it does not agree that the new Measures and Levels of Non-
Compliance fully address the Commission's concerns stated in the NOPR.
The modified Reliability Standard does not contain Measures or Levels
of Non-Compliance corresponding to Requirement 8. This Requirement
deals with actions to restore real and reactive power balance. Given
the importance of these matters to reliable operations, the Commission
directs the ERO to provide Measures and Level of Non-Compliance for
this Requirement.
1582. We disagree with California PUC's assertion that the
Commission should not adopt TOP-001-1 unless it commits to a policy of
``appropriate deference'' to existing authorities. Approval of a
continent-wide Reliability Standard should not be delayed because it
may overlap with a local or regional program. Rather, stakeholders
should raise related concerns in the ERO Reliability Standards
development process. Moreover, section 215(i)(3) of the FPA provides
that ``nothing in [section 215] shall be construed to preempt any
authority of any State to take action to ensure the safety, adequacy,
and reliability of electric service within that State, as long as such
action is not inconsistent with any reliability standard.'' In any
event, California PUC does not suggest how the Requirements in TOP-001-
1 and the provisions of CAISO's participating generator agreements will
lead to conflicting outcomes. To the extent a potential conflict
arises, we note that the CAISO's participating generator agreements are
subject to Commission jurisdiction, and Sec. 39.6 of the Commission's
regulations provides procedures for resolving conflicts between a
requirement in a Reliability Standard and a provision of an agreement
accepted for filing at the Commission.\400\
---------------------------------------------------------------------------
\400\ See 18 CFR 39.6 (Conflict of a Reliability Standard with a
Commission Order).
---------------------------------------------------------------------------
1583. We agree with FirstEnergy that TOP-001-1 should establish a
clear line of authority. Requirement R3 of Reliability Standard IRO-
001-0 clearly establishes the decision-making authority of the
reliability coordinator to act and to direct actions to be taken by
operating entities to preserve the integrity and reliability of the
Bulk-Power System. When an entity is faced with conflicting directives,
it must follow the reliability coordinator's directives because the
reliability coordinator is the highest authority in matters affecting
reliability of the Bulk-Power System. Therefore no changes are required
to the Reliability Standard in this connection.
1584. We agree with MEAG Power that a reliability directive to an
LSE to increase its planning reserve to 15 percent or to reconductor
its transmission line is outside the scope of
[[Page 16562]]
a TOP reliability directive. Reliability directives in the TOP group of
Reliability Standards deal with operational directives and not planning
directives.
1585. We disagree with MEAG Power that an entity may have to comply
with a reliability directive issued to it by a reliability coordinator
other than its host reliability coordinator. The operating hierarchy
embodied in the Reliability Standard gives the reliability coordinator
responsibility and authority to issue reliability directives to its own
transmission operators, balancing authorities and generator operators.
These entities must comply with these directives as stated in
Requirement R3 in TOP-001-1.\401\ An entity is only responsible for
following directives from its host reliability coordinator unless
authority is delegated to another reliability coordinator by the host
reliability coordinator.
---------------------------------------------------------------------------
\401\ The Requirement states in part that ``[e]ach Transmission
Operator, Balancing Authority, and Generator Operator shall comply
with reliability directives issued by the Reliability Coordinator* *
*.''
---------------------------------------------------------------------------
1586. We agree with FirstEnergy and California Cogeneration that
the definition of ``emergency'' could be further clarified. We discuss
this issue in this Final Rule in connection with Reliability Standard
EOP-001-0 and conclude that emergency states need to be defined and
that criteria for entering these states and authority for declaring
them need to be specified. We therefore direct the ERO to modify the
Reliability Standard accordingly. With respect to California
Cogeneration's argument regarding exemptions from the requirement to
respond to emergencies, the reliability coordinator must be in a
position to take all necessary actions in response to an emergency and
is in the best position to determine which entities should respond to
its directives.
1587. In response to FirstEnergy's request for clarification of the
meaning of ``safety'' in the first sentence of Requirement R4, of TOP-
001-1 and whether it refers to safety to the system/equipment, public
safety or both, the Commission notes that each term in the series set
forth in this provision refers to a type of ``requirement.'' \402\ The
provision clearly differentiates between the safety of persons and
equipment requirements. Since equipment requirements are mentioned
separately, safety must be read as referring to requirements related to
safety of persons.
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\402\ Requirement R4 states: ``Each Distribution Provider * * *
shall comply with all reliability directives * * * unless such
actions would violate safety, equipment, regulatory or statutory
requirements.''
---------------------------------------------------------------------------
1588. With regard to FirstEnergy's proposal that the entity
requesting emergency assistance be required to report that it has
implemented all of its own emergency procedures as part of its request
for emergency assistance, we believe that such reporting is not
appropriate during an emergency situation. Requirement R6 of the
Reliability Standard clearly specifies that entities must provide
available emergency assistance provided the requesting entity has
implemented its comparable emergency procedures. Given the nature of
emergency situations where time is of the essence, compliance with this
Requirement must be assessed after the fact as part of the compliance
audit, and not during an emergency.
1589. With respect to Santa Clara's proposal that Requirements R7.2
and R7.3 be revised to provide that the transmission operator may
notify the reliability coordinator or the balancing authority that it
is removing facilities from service, the Commission directs the ERO to
consider Santa Clara's comments in the Reliability Standards
development process.
1590. Accordingly, the Commission approves Reliability Standard
TOP-001-1. In addition, pursuant to section 215(d)(5) of the FPA and
Sec. 39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-001-1 through the Reliability Standards
development process that: (1) Includes Measures and Levels of Non-
Compliance for Requirement R8 and (2) considers adding other Measures
and Levels of Non-Compliance in the Reliability Standard.
b. Normal Operations Planning (TOP-002-2)
1591. Reliability Standard TOP-002-2 requires transmission
operators and balancing authorities to look ahead to the next hour, day
and season, and have operating plans ready to meet any unscheduled
changes in system configuration and generation dispatch. The
Reliability Standard addresses the following matters: (1) Procedures to
mitigate System Operating Limit (SOL) and Interconnection Reliability
Operating Limit (IROL) violations; (2) verification of real and
reactive reserve capabilities; (3) communications; (4) modeling; (5)
information exchange and (6) data confidentiality restrictions. The
goal of TOP-002-1 is to ensure that resources and operational plans are
in place to enable system operators to maintain the Bulk-Power System
in a reliable state.
1592. In the NOPR, the Commission proposed to approve the
Reliability Standard as mandatory and enforceable. In addition, the
Commission proposed to direct that NERC submit a modification that: (1)
Includes Measures and Levels of Non-Compliance; (2) deletes references
to confidentiality agreements in Requirements R3 and R4, but addresses
the issue separately to ensure that necessary protections are in place
related to confidential information and (3) requires next-day analysis
for all IROLs to identify and communicate control actions to system
operators that can be implemented within 30 minutes following a
contingency to return the system to a reliable operating state and
prevent cascading outages.\403\
---------------------------------------------------------------------------
\403\ In its November 15, 2006, filing, NERC submitted TOP-002-
2, which supercedes the earlier Reliability Standard. TOP-002-2 adds
Measures and Levels of Non-Compliance to the Reliability Standard,
and includes a modified Requirement R14. In this Final Rule, we
review the November version, TOP-002-2.
---------------------------------------------------------------------------
1593. The Commission also proposed to interpret Requirement R7 of
the Reliability Standard as requiring that each balancing authority
plan to meet capacity and energy reserve requirements, including
deliverability/capability for any single contingency. Although the NERC
glossary defines ``contingency,'' \404\ the Commission expressed
concern in the NOPR that the phrase ``single contingency'' is open to
interpretation, and ``deliverability'' is not defined. The Commission
proposed in the NOPR to interpret contingency as discussed in
connection with the TPL Reliability Standards and to interpret
deliverability as the ability to deliver the output from generation
resources to firm load without any reliability criteria violations for
plausible generation dispatches.
---------------------------------------------------------------------------
\404\ NERC defines ``contingency'' as ``the unexpected failure
or outage of a system component, such as a generator, transmission
line, circuit breaker, switch or other electric element.'' NERC
Glossary at 3.
---------------------------------------------------------------------------
i. Comments
1594. APPA states that NERC has added Measures for many but not all
of the Requirements of TOP-002-2 and needs to develop Measures for
Requirements R2, R3, R4, R12 and R17.
1595. Entergy and MidAmerican support the Commission's proposal to
delete references to confidentiality agreements from the requirements
and state that different approaches must be explored to preserve the
confidentiality of data. MidAmerican adds that NERC should adopt an
administrative approach to keep the confidential information from being
disclosed before the confidentiality provisions are
[[Page 16563]]
deleted from the requirements. LPPC asks the Commission to clarify that
CEII remains confidential and states that without such clarification
there is a danger that sensitive information related to the Bulk-Power
System will become public.
1596. FirstEnergy and Entergy express concerns regarding
identifying all control actions in the next-day analysis for all IROLs
to identify and communicate control actions to system operators that
can be implemented within 30 minutes following a contingency. They
contend that system conditions can change significantly between day-
ahead analysis and real-time operations, rendering potential control
actions irrelevant. Therefore they state that operating entities should
be held harmless for not having listed in advance control actions taken
in the face of real-time contingencies resulting from unpredicted
changing system conditions. APPA states that such requirements are not
necessary given that system operators use state estimators and other
tools to identify effective control actions that produce more accurate
results than would be achieved through the proposed day-ahead analysis.
APPA and Entergy assert that it should be left to NERC, as the
technical expert charged with setting standards, to decide in the first
instance whether such day-ahead analysis would be of sufficient benefit
to justify requiring it.
1597. MidAmerican is concerned that the Commission's proposal to
interpret the phrase ``single contingency'' as a contingency that
includes all multi-element pieces of the system that go out of service
together in response to a single event is too restrictive on system
operations. However, it also states that historically it has performed
the studies in accordance with the Commission's proposal and will
support that proposal in the interest of reliability. MidAmerican notes
that where a multiple-element single contingency traverses neighboring
systems, such contingencies must be coordinated with other systems.
Further, it contends that the Commission's directive to have operating
plans to meet any scheduled change in system configuration and
generation dispatch seems burdensome if not impossible and requests
clarification of the Commission's intent in this connection.
1598. ISO-NE recommends that the reference to ``transmission
service provider'' in Requirement R12 of TOP-002-2 should be replaced
by ``transmission operator'' and/or ``transmission owner.'' \405\ It
claims that such a change would be consistent with the definition of
the term ``transmission service provider,'' which the NERC glossary
defines as: ``[t]he entity that administers the transmission tariff and
provides Transmission Service to Transmission Customers under
applicable transmission service agreements.'' In performing this
function, the transmission service provider provides a business service
that entails executing contractual agreements with its customers to
provide open access transmission service, whereas SOLs and IROLs are
technical in nature and do not translate into transmission service
provider functions. In contrast, transmission operators and
transmission owners perform planning and operations functions and will
need SOL and IROL data.
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\405\ Requirement R12 provides: ``The Transmission Service
Provider shall include known SOLs and IROLs within its area and
neighboring areas in the determination of transfer capabilities, in
accordance with filed tariffs, and/or regional Total Transfer
Capability and Available Transfer Capability calculation
processes.''
---------------------------------------------------------------------------
1599. NRC states that it is not clear whether TOP-002-2 considers
the N-1 and the N-1-1 criteria consistent with TPL-002-0 and TPL-003-0,
respectively. NRC is concerned about verifying that the Bulk-Power
System will provide the necessary voltages to the auxiliary power
system busses after a nuclear power plant trip. It suggests that
knowledge and verification of significant generator characteristics are
essential to this end, especially verification of real and reactive
capabilities, automatic voltage regulator status and operating limits.
NRC also proposes various revisions to TOP-002-2.
ii. Commission Determination
1600. The Commission approves Reliability Standard TOP-002-2 as
mandatory and enforceable. In addition, we direct the ERO to develop
modifications to the Reliability Standard through the Reliability
Standards development process as discussed below.
1601. We are adopting our proposal regarding deletion of references
to confidentiality agreements from the Requirements. As we explained in
the NOPR, the effectiveness of a Reliability Standard should not be
predicated upon the existence of a confidentiality agreement.\406\ The
ERO should address the confidentiality provision separately to ensure
that confidentiality of data is not compromised and CEII information
remains confidential.
---------------------------------------------------------------------------
\406\ NOPR at P 976.
---------------------------------------------------------------------------
1602. As noted above, a number of commenters express concerns with
the Commission's proposal to require a next-day analysis for all IROLs
to identify and communicate control actions to system operators.
Identification and communication of control actions that can be
implemented within 30 minutes are required to ensure that system
operators are aware of and have options available to respond to system
conditions following the first contingency to restore the system to a
secure state so that it can withstand the next contingency. In
addition, the control actions identified in the next-day analysis may
quite often be relevant, and informing the system operators of the
control options earlier on would be helpful. While the operators may
take other actions to preserve the system, they need to have at least
one plan (control actions) that will preserve the system from
cascading. We believe this addresses FirstEnergy's concern regarding
whether compliance requires the use of only the control actions
identified in the day-ahead analysis. In response to APPA's comment on
the use of state estimators and other tools to identify effective
control actions, we note that this capability will help operators in
assessing system responses, but they will not identify the control
actions system operators will need to take in real-time. Further,
operators may not be aware of available control actions, or worse they
may not have any control actions, other than firm load-shedding,
available to adjust the system after a first contingency occurs.
Therefore, we direct the ERO to modify Reliability Standard TOP-002-2
to require the next-day analysis for all IROLs to identify and
communicate control actions to system operators that can be implemented
within 30 minutes following a contingency to return the system to a
reliable operating state and prevent cascading outages.
1603. With respect to NRC's comments, system operators must operate
the system in front of them at all times to be capable of withstanding
a critical contingency (N-1) without resulting in instability,
uncontrolled separation or cascading failures. After this N-1
contingency the operators must adjust the system as soon as possible
and in no longer than 30 minutes so that the system can then withstand
a new N-1 contingency. Further discussion of how this applies in the
planning arena is presented in connection with the TPL group of
Reliability Standards.
[[Page 16564]]
1604. The Commission agrees with NRC that the minimum voltages at
nuclear plant auxiliary power system buses should be assessed in next-
day analysis to ensure that adequate voltages can be maintained in
accordance with the nuclear plant minimum voltage requirements. If this
assessment projects that the minimum voltage requirements cannot be
met, the transmission operators or balancing authorities must notify
the nuclear power plant as soon as possible, but in no event later than
the commencement of the next day's real-time operations. If during
real-time operations the transmission operator cannot maintain the
minimum voltage, pre- or post-contingency, it must inform the nuclear
plant operator accordingly so that the appropriate corrective actions
can be carried out by both the nuclear plant operator and the
transmission operator. The Commission directs the ERO to modify
Reliability Standard TOP-002-2 to address these two issues.
1605. The Commission proposed in the NOPR that simulations must be
consistent with the number of elements that will be removed from
service as a result of the failure of a single element.\407\
MidAmerican states that it operates consistent with this proposal, in
that it respects a single contingency as one that includes all multiple
pieces of the elements that go out of service together in response to a
single event. Even though MidAmerican states that the Commission's
proposal is too restrictive on system operation, it supports the
proposal in the interest of reliability. To do otherwise would not
represent what actually happens in real-time operations to the
detriment of Bulk-Power System reliability, which demonstrates the need
to approach the issue as we propose. We discuss this issue further in
connection with the TPL group of Reliability Standards, where we direct
the ERO to modify the TPL Reliability Standards to simulate what
actually happens in the physical system, including multiple element
failures.
---------------------------------------------------------------------------
\407\ NOPR at P 979.
---------------------------------------------------------------------------
1606. We note with regard to MidAmerican's comment on operating
plans to meet any scheduled change in system configuration and
generation dispatch that we have not directed any action in this
connection and therefore cannot provide any further clarification on
this point. With regard to MidAmerican's comment on coordinated efforts
with neighboring systems to deal with multiple element single
contingencies, we note that such coordination is already required by
IRO and TOP Reliability Standards.
1607. Commenters did not take issue with the proposed
interpretation of the term ``deliverability'' as ``the ability to
deliver the output from generation resources to firm load without any
reliability criteria violations for plausible generation dispatches.''
\408\ The Commission adopts this proposed interpretation. In order to
ensure the necessary clarity, the term as used in Requirement R7 of
TOP-002-2 should be understood in this manner.
---------------------------------------------------------------------------
\408\ Id. at P 974.
---------------------------------------------------------------------------
1608. With respect to the modifications to Requirement R12 of the
Reliability Standard recommended by ISO-NE and NRC's comments on
Measure M7 and a new Measure M11, the Commission directs the ERO to
consider these matters in the Reliability Standards development
process. In response to NRC's suggestion regarding periodic review of
generators' reactive capability, we note that Reliability Standard MOD-
025-1 already requires periodic review of generators' reactive
capability.
1609. As we explained in the NOPR, TOP-002-2 serves an important
purpose in ensuring that resources and operational plans are in place
to enable system operators to maintain the Bulk-Power System in a
reliable state. Further, the requirements set forth in the Reliability
Standard are sufficiently clear and objective to provide guidance for
compliance. Accordingly, the Commission approves Reliability Standard
TOP-002-2. In addition, pursuant to section 215(d)(5) of the FPA and
Sec. 39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-002-2 through the Reliability Standards
development process that: (1) Deletes references to confidentiality
agreements in Requirements R3 and R4, but addresses the issue
separately to ensure that necessary protections are in place related to
confidential information; (2) requires the next-day analysis for all
IROLs to identify and communicate control actions to system operators
that can be implemented within 30 minutes following a contingency to
return the system to a reliable operating state and prevent cascading
outages; (3) requires next-day analysis of minimum voltages at nuclear
power plants auxiliary power busses and (4) requires simulation
contingencies to match what will actually happen in the field.
c. Planned Outage Coordination (TOP-003-0)
1610. Reliability Standard TOP-003-0 requires transmission
operators that operate facilities greater than 100 kV, generator
operators that operate facilities greater than 50 MW and balancing
authorities to coordinate transmission and generator maintenance
schedules. Where a conflict in maintenance schedule arises, the
reliability coordinator is authorized to resolve the conflict.
1611. The Commission proposed in the NOPR to approve Reliability
Standard TOP-003-0 as mandatory and enforceable. The Commission also
proposed to direct NERC to submit a modification to TOP-003-0 that: (1)
Includes a requirement to communicate scheduled outages well in advance
to ensure reliability and accuracy of ATC calculation and (2) makes any
facility below the 100 kV or 50 MW thresholds that, in the opinion of
the transmission operator, balancing authority, or reliability
coordinator, will have a direct impact on the operation of Bulk-Power
System subject to Requirement R1 for planned outage coordination.
1612. In addition, the Commission noted in the NOPR that outage
information is important to both reliable operation and to the
calculation of ATC. This information is also needed to assure
coordination of outages long before next day or current day operations.
The Commission proposed that applicable scheduled outages be
communicated to affected transmission operators and reliability
coordinators with sufficient lead time to coordinate outages. The
Commission then requested industry input on what constitutes sufficient
lead time for planned outages.
i. Comments
1613. MRO, APPA and others raise concerns requiring the proposed
requirement to communicate scheduled outages ``well in advance.'' APPA
cautions that TOP-003-0 was generally designed to ensure that
transmission operators receive accurate and timely information about
transmission and generation outages affecting ``next-day operations,''
rather than the longer term outage planning information. MRO states
that requiring outage information well in advance reduces the entity's
flexibility for other contingencies and changes. MRO also contends that
the phrase ``well in advance'' is vague, not measurable, and may not be
enforced fairly and consistently. FirstEnergy states that NERC should
specify the meaning of ``well in advance'' through its Reliability
Standards development process with industry input. MRO recommends that
the time period for outage notification should be based on the size of
the generating facility and voltage level of the transmission line so
[[Continued on page 16565]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 16565-16602]] Mandatory Reliability Standards for the Bulk-Power System
[[Continued from page 16564]]
[[Page 16565]]
that a larger facility has a longer lead time for outage notification.
1614. While MISO agrees with the need for early notification of
planned outages, it is concerned that an arbitrary lead time will cause
entities to postpone needed maintenance to accommodate the timeline,
thereby reducing the reliability of the Bulk-Power System.
1615. LPPC states that business reasons often drive a longer lead
time for outage planning to allow market participants to better
understand the congestion and market impacts of the planned outage.
LPPC believes that the Commission should exercise caution and avoid
adopting a business practice as part of the Reliability Standard.
Reliability concerns often dictate that an outage should not be planned
and set in stone too far in advance because the circumstances may
change. According to LPPC, the Commission should refrain from
prescribing a lead time that would cut into an operator's flexibility,
which is needed to respond to real-time situations.
1616. In response to the Commission's question regarding the lead
time for planned outages, MidAmerican states that although it believes
that a requirement for extending the lead time will result in higher
costs and less flexibility, a two-week advance notice for planned
outages of 345 kV facilities and one-week advance notice for 161 and 69
kV facilities is appropriate. TVA proposes one-week advance notice for
all planned outages and recommends that TOP-003-0 should be modified to
include breaker outages within the meaning of the facilities that are
subject to advance notice for planned outages.
1617. CAISO states that its current tariff provides for three days
of lead time for providing outage information and that this is a
standard practice throughout WECC. It maintains, however, that the
three-day lead time is not sufficient for the needed review and
coordination of outages. In fact, CAISO states that many ISOs and RTOs
are moving toward a lead time of either 30 days or 45 days prior to the
beginning of the outage month. CAISO contends that rather than basing
the outage information on a certain kV level, the emphasis should be on
facilities that may have a significant effect on congestion revenue
rights resource adequacy.
1618. Entergy and FirstEnergy support the proposed modification to
include any facility below the thresholds that, in the opinion of the
transmission operator, balancing authority, or reliability coordinator,
will have a direct impact on the operation of the Bulk-Power System
subject to Requirement R1 for planned outage coordination. They
maintain that such a modification will provide the transmission
operator much needed flexibility. APPA, on the other hand, opposes the
proposal. APPA states that the Commission should allow the ERO in the
first instance to consider whether to add this specific requirement to
TOP-003-0. If the Commission is concerned that TOP-003-0 as it now
stands might ``not include all facilities that have a significant
impact on the operation of the Bulk-Power System,'' it should direct
NERC to consider that issue on remand using its Reliability Standards
development process.
1619. Xcel notes that Requirement R4 of the Reliability Standard
provides that each reliability coordinator should resolve any potential
conflicts in scheduling of planned outages. Xcel argues that if a
reliability coordinator requires an entity to move its planned outage
to accommodate another entity's unplanned outage, the entity that
agrees to move its planned outage to another time should receive
compensation.
ii. Commission Determination
1620. The Commission approves TOP-003-0 as mandatory and
enforceable. We address the concerns raised by commenters below.
1621. In Order No. 890, the Commission directed that information
concerning ATC calculations be consistent and transparent.\409\ The
timing of facility outages is one important piece of information in ATC
calculations. In Order No. 890, the Commission directed that specific
data be exchanged among transmission providers, including transmission
planned and contingency outages, for the purpose of ATC modeling.\410\
Consistent with this determination in Order No. 890, the Commission
directs the ERO to develop a modification to TOP-003-0 that requires
the communication of scheduled outages to all affected entities well in
advance to ensure reliability and accuracy of ATC calculations.\411\ We
believe this addresses LPPC's concern regarding the interplay between
reliability and business practices.
1622. Several commenters raised concerns regarding the Commission's
proposal to require outage information well in advance. Specifically,
they argue that the term ``well in advance'' is vague, that the
requirement would reduce flexibility and that it would cause entities
to postpone needed maintenance work, thereby reducing reliability. In
response to the Commission's request for comments on lead time for
planned outages, entities provide information on current lead time
practices indicating that lead times range from one week to 45 days. We
direct the ERO to modify the Reliability Standard to incorporate an
appropriate lead time for planned outages. The ERO should utilize the
information filed by commenters in the Reliability Standards
development process. In doing so the ERO should take into consideration
the need for flexibility, as well the lead time required for
coordination with other entities and outage assessments. Proper
coordination will ensure that priority is given to needed maintenance
work for critical facilities to ensure reliability.
---------------------------------------------------------------------------
\409\ See Order No. 890 at P 68-69, 207-213.
\410\ Id. at P 292.
\411\ The Commission notes that PJM has developed an outage
scheduling process in response to Commission directives to avoid the
possibility of undue discrimination. http://www.pjm.com/committees/mrc/downloads/20060630-item-06-draft-manual-14b-changes.pdf.
The
outage scheduling process was developed through a stakeholder
process and has been utilized in the entire PJM footprint for a
number of years. PJM's outage scheduling program is one example of
the type of program that should be implemented through the
Reliability Standard.
---------------------------------------------------------------------------
1623. With regard to TVA's request to include breaker outages
within the meaning of the facilities that are subject to advance notice
for planned outages, we direct the ERO to consider this suggestion in
the Reliability Standards development process.
(a) Applicability
1624. As noted above, the Commission proposed to direct the ERO to
modify TOP-003-0 to make any facility below the thresholds that, in the
opinion of the transmission operator, balancing authority, or
reliability coordinator, will have a direct impact on the operation of
Bulk-Power System subject to Requirement R1 for planned outage
coordination.
1625. Entergy and FirstEnergy support the proposed modification to
include any facility below the threshold that in the opinion of the
reliability coordinator, balancing authority or transmission operator
will have a direct impact on the operation of the Bulk-Power System. On
the other hand, APPA opposes this proposal and contends that the
Commission should allow the ERO, as the expert entity charged with
developing Reliability Standards, to consider whether to add this
specific requirement. The Commission disagrees because registered
entities below the thresholds currently defined in Requirement R1 of
the Reliability Standard may have an impact on reliability and
therefore should be required to submit data on their planned outages.
The Commission therefore directs the ERO to modify the
[[Page 16566]]
Reliability Standard to require that any facility below the thresholds
that, in the opinion of the transmission operator, balancing authority,
or reliability coordinator will have a direct impact on the reliability
of the Bulk-Power System be subject to Requirement R1 for planned
outage coordination.
(b) Other Issues
1626. In response to Xcel's proposal that entities that agree to
reschedule their previously-approved planned outages to accommodate
another entity's unplanned outage be compensated, the Commission notes
that whereas rescheduling of the outage is a reliability matter,
compensation is not and therefore is outside the scope of this
proceeding.
(c) Summary of Commission Determination
1627. Planned outage coordination is a necessary element of
reliable operations, and TOP-003-0 promotes that goal. Accordingly, the
Commission approves the Reliability Standard 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 directs the ERO to
develop a modification to TOP-003-0 through the Reliability Standards
development process that: (1) Includes a new requirement to communicate
longer term outages well in advance to ensure reliability and accuracy
of ATC calculation; (2) makes any facility below the voltage thresholds
that, in the opinion of the transmission operator, balancing authority,
or reliability coordinator, will have a direct impact on the operation
of Bulk-Power System, subject to Requirement R1 for planned outage
coordination and (3) incorporates an appropriate lead time for planned
outages as discussed above.
d. Transmission Operations (TOP-004-1)
1628. This Reliability Standard requires transmission operators to
operate the transmission system within SOL and IROL.\412\ The N-1
operating criterion for the transmission system is also established in
this Reliability Standard. It provides that operating configurations
for which limits have not yet been determined should be treated as
emergencies. The goal of the Reliability Standard is to maintain Bulk-
Power System facilities within limits, thereby protecting transmission,
generation, distribution and customer equipment and preventing
cascading failures of the interconnected grid.
1629. The Commission proposed in the NOPR to approve the
Reliability Standard as mandatory and enforceable. In addition, the
Commission proposed to direct that NERC submit a modification that: (1)
Includes Measures and Levels of Non-Compliance; (2) clarifies that the
system should be restored as soon as possible, taking no more than 30
minutes and (3) defines high risk conditions under which the system
must be operated to respect multiple outages in Requirement R3. The
Commission also proposed to direct the ERO to perform a survey of the
prevailing operating practices and actual operating experiences
surrounding drifting in and out of IROL limits.
1630. Requirement R3 requires that each transmission operator
shall, when practical, operate the system to respect multiple outages
as specified by the regional reliability organization policy. The
Commission noted in the NOPR that Requirement R3 does not define
conditions under which multiple outages must be considered. The NOPR
proposed to interpret such conditions ``to include high risk conditions
such as hurricanes, ice storms or periods of high solar magnetic
disturbances during which the probability of multiple outages
approaches that of a single element outage.'' \413\
i. Comments
1631. PG&E and APPA oppose a modification to the Reliability
Standard that changes the requirement allowing operators to return the
system to a reliable operating state within 30 minutes to a requirement
that they do so as soon as possible and in no longer than 30 minutes.
PG&E is concerned that during emergencies operators would be subject to
uncertainty in complying with such a requirement, which could lead to
overly hasty responses with a corresponding detrimental effect on
reliability. PG&E states that to avoid the confusion and ambiguity from
a subjective standard, the Commission and NERC should only clarify that
operators should seek to return the system to a reliable operating
state as soon as possible, but maintain the current requirement of 30
minutes as stated in Requirement R4 of TOP-004-1. APPA states that if
the Commission is concerned about the need to require a response time
that is quicker than 30 minutes, it should direct the ERO to consider
this issue as part of the Reliability Standards development process.
1632. Entergy and MidAmerican support the Commission's proposal to
have NERC conduct a survey and report the operating practices and
actual experiences surrounding drifting in and out of IROL violations.
MISO, on the other hand, opposes the survey because there are already
requirements for reporting IROL violations elsewhere in the Reliability
Standards. APPA proposes that the Commission should ask the ERO to
determine if such information would improve reliable operations. If it
is determined that such information will improve reliability, NERC
should include this type of information in compliance violation
reporting procedures.
1633. LPPC and Xcel recommend that the Commission not require NERC
to define in Requirement R3 the specific high-risk conditions under
which the system must be operated to respect multiple outages. Xcel
argues that it is unnecessary and impractical to attempt to define in
advance all of the possible scenarios that will result in a high-risk
condition. Not all high-risk conditions can be defined at any one time
because changes in the system will introduce new high-risk conditions.
Even if a list of high-risk conditions is developed, then, by
definition, all other conditions not listed are excluded from
consideration under this Reliability Standard. LPPC states that the
proposed modification to deal with high-risk conditions is an
unnecessarily prescriptive approach and could be detrimental to
reliability by excluding scenarios that should be listed under this
Requirement.
---------------------------------------------------------------------------
\412\ In its November 15, 2006, filing, NERC submitted TOP-004-
1, which has an effective date of October 1, 2007, at which time it
will supercede the Version 0 Reliability Standard. TOP-004-1 adds
Measures and Levels of Non-Compliance to the Version 0 Reliability
Standard. Because TOP-004-0 will be in effect until October 1, 2007
and TOP-004-1 thereafter, we address both versions of the
Reliability Standard.
\413\ NOPR at P 997.
---------------------------------------------------------------------------
1634. California PUC states that the Commission should not
interpret hurricanes and ice storms as high risk conditions for
studying multiple outages because events such as hurricanes and ice
storms actually reduce the stress on the Bulk-Power System. This is
because such events cause outages at the local distribution system
level. California PUC maintains that since events such as hurricanes
and ice storms rarely cause cascading outages, the proper approach for
dealing with such situations is to focus on system restoration planning
rather than including them in the contingency analysis that the
proposed modification will require as a result of including such
natural events within the meaning of high risk conditions.
1635. Santa Clara states that Requirement R2 of the Reliability
Standard should be revised to include
[[Page 16567]]
frequency monitoring in addition to the monitoring of voltage, real and
reactive power flows.
ii. Commission Determination
1636. The Commission approves TOP-004-0 as mandatory and
enforceable until October 1, 2007, when TOP-004-1 will be mandatory and
enforceable. We address the concerns raised by commenters below.
1637. We adopt our proposal to require the ERO to clarify that the
system should be restored as soon as possible, taking no more than 30
minutes. Requirement R4 of TOP-004-1 (as well as the Version 0
standard) provides that if a transmission operator enters an unknown
state, i.e., any state for which valid operating limits have not been
determined, operations should be restored to respect proven reliable
power system limits within 30 minutes. However, as we stated in the
NOPR, this language may be interpreted as a grace period to the
detriment of reliability.\414\ The Commission, therefore, directs that
the ERO develop a modification to Requirement R4 providing that the
system should be restored to respect proven reliable power system
limits as soon as possible and in no longer than 30 minutes. In
response to PG&E's point that the phrase ``as soon as possible'' would
add confusion, we note that Measure M1 in TOP-004-1 would measure
performance against the 30-minute period specified in Requirement R4.
---------------------------------------------------------------------------
\414\ See NOPR at P 995.
---------------------------------------------------------------------------
1638. Entergy and MidAmerican support our proposal to direct the
ERO to conduct a survey and report the operating practices and actual
experiences surrounding drifting in and out of IROL violations. We
disagree with MISO that TOP-007-0 covers reporting of ``drifting'' in
and out of IROL violations because that Reliability Standard only
requires reporting of IROL violations exceeding 30 minutes. With regard
to APPA's suggestion that NERC should determine whether such
information would improve reliable operations, we believe a survey is
appropriate to determine actual practices, and simply modifying the
compliance reporting procedures may not provide sufficient data to
determine the reliability impacts of such practices and whether a
modification to the Reliability Standard is appropriate. Accordingly,
we direct the ERO to conduct a survey on the operating practices and
actual experiences surrounding drifting in and out of IROL violations.
Such a survey will provide factual support for whether additional
modifications to the Reliability Standard are needed. The survey will
also indicate whether additional vigilance on the part of compliance
auditors is warranted in this area to ensure Bulk-Power System
reliability.
1639. As mentioned above, the Commission proposed to interpret
``multiple outages'' in the context of Requirement R3 to include
multiple element outages resulting from high-risk conditions such as
hurricanes, wild fires, ice storms or periods of high solar magnetic
disturbances during which the probability of multiple outages
approaches that of a single element outage. This is not an exhaustive
list but is meant to contain illustrative examples, and the Reliability
Standards development process should develop a procedure to identify
applicable high risk conditions. Under the high-risk conditions, the
Commission understands that systems are normally operated in a more
secure manner so that the Bulk-Power System can withstand multiple
outages. These multiple outages exceed the normal N-1 criterion because
the probability of multiple outages during high-risk conditions
approaches that of a single outage during normal conditions. This does
not preclude development of restoration plans as suggested by
California PUC. Thus, we direct the ERO to develop a modification to
the Reliability Standard that explicitly incorporates this
interpretation with the details identified in the Reliability Standards
development process.
1640. We direct the ERO to consider Santa Clara's suggestion
regarding changes to Requirement R2 in the Reliability Standards
development process.
1641. Accordingly, the Commission approves Reliability Standard
TOP-004-0. Further, we approve TOP-004-1 so that it will become
mandatory and enforceable on the stated effective date of October 1,
2007. In addition, pursuant to section 215(d)(5) of the FPA and Sec.
39.5(f) of our regulations, the Commission directs the ERO to develop a
modification to the Reliability Standard through the Reliability
Standards development process that: (1) Modifies Requirement R4 to
state that the system should be restored to respect proven limits as
soon as possible, taking no more than 30 minutes and (2) defines high
risk conditions under which the system must be operated to respect
multiple outages in Requirement R3, consistent with the discussion
above.
1642. In addition, the Commission directs the ERO to perform a
survey of the prevailing operating practices and actual operating
experiences surrounding drifting in and out of IROL limits as discussed
more fully in this Final Rule in connection with the IRO group of
Reliability Standards. As an example of the type of data that would be
appropriate in the survey, we would expect to have reliability
coordinators report any violation of an IROL not exceeding 30 minutes,
its causes, the date and time of the violation, and the duration for
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. The ERO should report the results to the Commission in an
informational filing within 18 months from the effective date of this
Final Rule.
e. Operational Reliability Information (TOP-005-1)
1643. Reliability Standard TOP-005-1 seeks to ensure that
reliability information is shared among reliability coordinators,
transmission operators and balancing authorities. It requires the
transmission operator and the balancing authority to provide operating
data to each other and to the reliability coordinator, and it provides
a list of typical operating data that must be provided. TOP-005-1 also
provides that each data recipient must execute a confidentiality
agreement as a condition of receiving data from NERC's Interregional
Security Network.\415\
---------------------------------------------------------------------------
\415\ Interregional Security Network is a data exchange system
that facilitates the exchange of real-time and other operational
data among reliability coordinators, balancing authorities and
transmission operators to help ensure reliable electric power system
operations.
---------------------------------------------------------------------------
1644. The Commission proposed in the NOPR to approve Reliability
Standard TOP-005-1 as mandatory and enforceable. The Commission also
proposed to direct NERC to submit a modification to TOP-005-1 that: (1)
Includes information about the operational status of special protection
systems and power system stabilizers in Attachment 1 and (2) deletes
references to confidentiality agreements, but addresses the issue
separately to ensure that necessary protections are in place related to
confidential information.
i. Comments
1645. FirstEnergy states that TOP-005-1 should also apply to
transmission providers because some of the information listed in
Attachment 1 to the Reliability Standard is in their possession.
Attachment 1 should be modified so that it allows each entity to know
what data it is expected to provide. As currently written, Attachment 1
lists various entities that are supposed to provide data without
[[Page 16568]]
specifying who will provide which information. FirstEnergy states that
transmission operators, for example, may not have all the information
listed in item 1.5 of Attachment 1.
1646. APPA and Entergy agree that TOP-005-1 should be modified to
include information about the operational status of special protection
systems and power system stabilizers in Attachment 1. However, APPA
contends that the Commission's directive should be revised so that this
change is developed through the Reliability Standards development
process.
1647. ISO-NE recommends that the reference to ``purchasing-selling
entity'' in Requirement R4 should be replaced with ``generator owner,
transmission owner, and LSE.'' \416\ It argues that since NERC's
glossary defines the term ``purchasing-selling entity'' as ``[t]he
entity that purchases or sells, and takes title to, energy, capacity,
and Interconnected Operation services,'' many entities can fall within
this category (e.g., commodity traders such as financial/power
marketers) that may possess little or none of the operational or
reliability data the host balancing authority and transmission operator
need to conduct reliability assessments.
---------------------------------------------------------------------------
\416\ Requirement R4 states: ``Each Purchasing-Selling Entity
shall provide information as requested by its Host Balancing
Authorities and Transmission Operators to enable them to conduct
operational reliability assessments and coordinate reliable
operations.''
---------------------------------------------------------------------------
1648. A number of commenters discussed the Commission's proposal to
delete references to confidentiality agreements in the Reliability
Standard but to address the issue separately to ensure that necessary
protections are in place related to confidential information. Those
comments are summarized above in connection with the same proposal made
by the Commission in the case of TOP-002-1.
ii. Commission Determination
1649. For the reasons stated in the NOPR,\417\ we direct the ERO to
develop a modification to TOP-005-1 through the Reliability Standards
development process regarding the operational status of special
protection systems and power system stabilizers in Attachment 1.
Several commenters agree with this directive, and we believe that this
information will provide a more comprehensive list in Attachment 1.
---------------------------------------------------------------------------
\417\ NOPR at P 1005.
---------------------------------------------------------------------------
1650. We are adopting our proposal regarding deletion of references
to confidentiality agreements from the Requirements. Our discussion of
this matter in connection with TOP-002-1 applies equally here.
1651. The Commission directs the ERO to consider FirstEnergy's
recommended modifications to Attachment 1 to the Reliability Standard
and ISO-NE's recommended revision to Requirement R4 in the Reliability
Standards development process.
1652. Accordingly, the Commission approves Reliability Standard
TOP-005-1. In addition, pursuant to section 215(d)(5) of the FPA and
Sec. 39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-005-1 through the Reliability Standards
development process that: (1) Includes information about the
operational status of special protection systems and power system
stabilizers in Attachment 1 and (2) deletes references to
confidentiality agreements, but addresses the issue separately to
ensure that necessary protections are in place related to confidential
information.
f. Monitoring System Conditions (TOP-006-1)
1653. TOP-006-1 requires operating personnel to continuously
monitor essential Bulk-Power System parameters such as line flows,
circuit breaker status, generator resources, relays, weather forecasts
and frequency to ensure that the facilities do not exceed their
operating limits.
1654. The Commission proposed in the NOPR to approve the
Reliability Standard as mandatory and enforceable.\418\ The Commission
also proposed to direct NERC to submit a modification that: (1)
Includes Measures and Levels of Non-Compliance; (2) includes a new
Requirement related to the provision of a minimum set of analytical
tools that will aid in situational awareness and (3) clarifies the
meaning of ``appropriate technical information'' concerning protective
relays.
---------------------------------------------------------------------------
\418\ In its November 15, 2006 filing, NERC submitted TOP-006-1,
which supersedes the Version 0 Reliability Standard. TOP-006-1 adds
Measures and Levels of Non-Compliance to the Version 0 Reliability
Standard. In this Final Rule, we review the November version, TOP-
006-1.
---------------------------------------------------------------------------
i. Comments
1655. Dominion supports including a new requirement for a minimum
set of analytical tools. It argues that such a requirement will ensure
that operators have a minimum set of tools with which to perform their
duties. The Reliability Standard should also specify metrics that can
be audited, such as minimum availability times, so that these tools are
adequately maintained. However, Alcoa states that requiring a minimum
set of tools will be unduly onerous, especially to smaller balancing
authorities and transmission operators. Although situational awareness
tools, such as state estimators, are critical for an ISO and RTO,
smaller balancing authorities and transmission operators should provide
necessary data to the reliability coordinator that monitors a wide
region using such tools.
1656. Alcoa claims that developing additional capability at the
balancing authority and transmission operator levels when such
capability already exists at the reliability coordinator level will be
redundant. Requiring state estimation for a small balancing area that
is under an ISO would provide little benefit for grid reliability since
the scope of the balancing area's visibility is limited.
1657. APPA does not support the proposed requirement related to the
provision of a minimum set of analytical tools and claims that
inclusion of specific analytical tools is counterproductive because the
tools become obsolete within two to five years due to technical
advances. APPA states that deciding whether to add a new requirement
for a minimum set of analytical tools should be left to NERC in the
first instance. Similarly, TAPS argues that NERC should consider in the
first instance whether minimum analytical tools are necessary and for
what subset of generator operators and transmission operators.
1658. LPPC maintains that the Commission should require NERC to
list the capabilities required rather than specific tools because tools
will change over time.
1659. APPA states that the ERO's filing on November 15, 2006
includes new Measures M1 through M6, which only measure Requirements
R1, R2, R4, R5 and R7.
ii. Commission Determination
1660. The Commission approves TOP-006-1 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop
modifications to TOP-006-1 through the Reliability Standards
development process, as discussed below.
1661. We adopt our proposal to require the ERO to develop a
modification related to the provision of a minimum set of analytical
tools. In response to LPPC and others, we note that our intent was not
to identify specific sets of tools, but rather the minimum capabilities
that are necessary to enable operators to deal with real-time
situations and to ensure reliable operation of the Bulk-Power System.
In response to APPA that the inclusion of specific analytical tools is
counterproductive because the tools
[[Page 16569]]
will become obsolete, we note that we are not seeking specific
analytical tools, but rather minimum capabilities.
1662. In regard to Alcoa's concern that this new Requirement would
be unduly onerous, especially for smaller balancing authorities and
transmission operators, the Commission's intent is not to subject
smaller balancing authorities and transmission operators to the same
requirements placed on larger balancing authorities and transmission
operators. As part of the modification of this Reliability Standard to
develop a new requirement for minimum capability for analytical tools,
the ERO should take into account what would be required of smaller
balancing authorities and transmission operators for the Reliable
Operation of the Bulk-Power System, instead of applying the same
requirements as are placed on other reliability entities such as
reliability coordinators and larger balancing authorities and
transmission operators.
1663. We disagree with Alcoa that developing additional capability
at the balancing authority and transmission operator levels when such
capability already exists at the reliability coordinator level will be
redundant. We are not seeking to duplicate the same capability for each
reliability entity, but rather the new requirement should specify the
minimum capability taking into account the role played by each entity.
For example, a reliability coordinator may need to have access to state
estimator and contingency analysis whereas a generator operator may not
need these capabilities.\419\
---------------------------------------------------------------------------
\419\ We note that TOP-006-0 applies to transmission operators,
balancing authorities, generator operators and reliability
coordinators.
---------------------------------------------------------------------------
1664. No commenters addressed our proposal with respect to the
meaning of ``appropriate technical information'' concerning protective
relays in Requirement R3 of the Reliability Standard. To provide more
clarity, criteria that define what ``appropriate technical
information'' is necessary should be specified so that operators can
make better informed decisions. An example of such information would be
the allowable reclosing angle set in the existing relays and the
maximum angle at specific points in the Bulk-Power System that would be
acceptable to allow closing of lines during system restoration.
1665. The ERO should consider APPA's comment regarding the missing
Measures in the ERO's Reliability Standards development process.
1666. Accordingly, the Commission approves Reliability Standard
TOP-006-1. In addition, pursuant to section 215(d)(5) of the FPA and
Sec. 39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-006-1 through the Reliability Standards
development process that: (1) Includes a new requirement related to the
provision of minimum capabilities that are necessary to enable
operators to deal with real-time situations and to ensure reliable
operation of the Bulk-Power System and (2) clarifies the meaning of
``appropriate technical information'' concerning protective relays.
g. Reporting SOL and IROL Violations (TOP-007-0)
1667. TOP-007-0 requires that violations of SOL and IROL be
promptly reported to the reliability coordinator so that it can direct
corrective action and inform other affected systems. It also requires a
transmission operator to mitigate an IROL violation as soon as possible
but in no longer than 30 minutes. A transmission operator must take
``all appropriate actions up to and including shedding firm load'' to
return its system to a stable state within IROL. Finally, the
Reliability Standard requires that the reliability coordinator take
action to mitigate an SOL or IROL violation if the transmission
operator's actions are not effective.
1668. The Commission proposed in the NOPR to approve TOP-007-0 as
mandatory and enforceable.
1669. In the NOPR, the Commission solicited comment on potentially
overlapping matters addressed in Reliability Standards TOP-007-0 and
TOP-008-0.
i. Comments
1670. NERC recognizes that there are some redundancies and awkward
relationships among the various Reliability Standards, which are the
result of the translation from the previous operating policies where
each policy was treated as a separate set of concepts. NERC states that
its 2007-2009 Reliability Standards Work Plan addresses work to be done
to eliminate redundancies and better organize the Requirements across
Reliability Standards so as to provide a more logical presentation.
1671. APPA states that the concerns expressed in the NOPR about
overlapping matters between TOP-007-0 and TOP-008-0 should be referred
to the NERC Reliability Standards development process to better comport
with the statutory division of responsibility. FirstEnergy and SoCal
Edison state that Requirements R2 through R4 are clearly not reporting
activities and should be combined with the requirements of TOP-008.
1672. NRC states that some nuclear power plant voltage requirements
would result in SOL, i.e., the nuclear power plant voltage limits would
be an SOL as a result of the minimum and maximum voltages required at
the nuclear power plant switchyard, which typically has a tighter
operating band (a higher minimum and a lower maximum) than other nodes
in the system. It therefore recommends adding a new requirement that
states as follows: ``Following discovery of a potential contingency
that could result in an SOL being exceeded at a nuclear power plant
(e.g., at post-trip voltage), the transmission owner shall notify the
nuclear power plant operator as soon as possible but not longer than 30
minutes if the contingency has not been corrected.'' NRC also suggests
modifying the Measures and Compliance sections and Table 1 to account
for the new requirement, and provides specific language to be included
in those places.
ii. Commission Determination
1673. The Commission approves TOP-007-0 as mandatory and
enforceable. We agree with APPA, FirstEnergy and SoCal Edison that the
Reliability Standards would benefit from the elimination of overlapping
matters in TOP-007-0 and TOP-008-1. The ERO indicates that it plans to
address this as part of its Work Plan and this suffices.
1674. NRC has raised some significant issues regarding the
consideration of nuclear power plants voltage requirements. Consistent
with our general approach in this Final Rule, we direct the ERO to
consider NRC's comments in the Reliability Standards development
process when addressing TOP-007-0 as part of its Work Plan.
1675. Accordingly, the Commission approves Reliability Standard
TOP-007-0 as mandatory and enforceable.
h. Response to Transmission Limit Violations (TOP-008-1)
1676. TOP-008-1 requires a transmission owner to take immediate
steps to mitigate SOL and IROL violations.
1677. The Commission proposed in the NOPR to approve Reliability
Standard TOP-008-0 as mandatory and enforceable. The Commission also
proposed to direct that NERC submit a modification to TOP-008-0 that:
(1) Includes Measures and Levels of Non-Compliance and (2) includes
reliability
[[Page 16570]]
coordinators in the applicability section.\420\
---------------------------------------------------------------------------
\420\ In its November 15, 2006, filing, NERC submitted TOP-008-
1, which supersedes the Version 0 Reliability Standard. TOP-008-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, TOP-008-1.
---------------------------------------------------------------------------
i. Comments
1678. APPA questions whether TOP-008-1 should be modified to apply
to reliability coordinators. It claims that the Requirement R3 simply
mentions that the reliability coordinator will receive information
provided by the transmission operator and does not play any substantive
role under TOP-008-1. MISO notes that the reliability coordinators'
responsibility related to IROL violations are outlined in connection
with IRO Reliability Standards and the reasons for adding the
reliability coordinator as applicable entity in multiple locations is
unclear.
1679. APPA states that NERC has not submitted a Measure for the
Requirement R2 of the Reliability Standard. The new Measures M1 through
M5 included in TOP-008-1 only measure Requirements R1, R3, and R4. In
addition, the data retention and compliance levels reference Measures
M1 through M5. Therefore, an entity subject to TOP-008-1 could arguably
comply with Requirements R1, R3 and R4 and be in compliance with the
entire Reliability Standard.
ii. Commission Determination
1680. For the reasons stated in the NOPR,\421\ the Commission
approves TOP-008-1 as mandatory and enforceable. We address the
concerns raised by commenters below.
---------------------------------------------------------------------------
\421\ See NOPR at P 1035-36.
---------------------------------------------------------------------------
1681. We agree with APPA that the reliability coordinator merely
receives information provided by the transmission operator and does not
play any substantive role under TOP-008-1. We also agree with MISO that
the reliability coordinators' responsibility related to IROL violations
are outlined in connection with the IRO Reliability Standards and
therefore there is no need to modify the applicability section of TOP-
008-1 to include the reliability coordinator.
1682. The ERO should consider APPA's comment regarding the missing
Measures in the ERO's Reliability Standards development process.
1683. Accordingly, the Commission approves Reliability Standard
TOP-008-1 as mandatory and enforceable.
12. TPL: Transmission Planning
1684. The Transmission Planning (TPL) group of Reliability
Standards consists of six Reliability Standards that are applicable to
transmission planners, planning authorities and regional reliability
organizations. These Reliability Standards are intended to ensure that
the transmission system is planned and designed to meet an appropriate
and specific set of reliability criteria. Transmission planning is a
process that involves a number of stages including developing a model
of the Bulk-Power System, using this model to assess the performance of
the system for a range of operating conditions and contingencies,
determining those operating conditions and contingencies that have an
undesirable reliability impact, identifying the nature of potential
options, and the need to develop and evaluate a range of solutions and
selecting the preferred solution, taking into account the time needed
to place the solution in service. The proposed TPL Reliability
Standards address: (1) The types of simulations and assessments that
must be performed to ensure that reliable systems are developed to meet
present and future system needs \422\ and (2) the information required
to assess regional compliance with planning criteria and for self-
assessment of regional reliability.\423\
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\422\ See TPL-001-0, TPL-002-0, TPL-003-0 and TPL-004-0.
\423\ See TPL-005-0 and TPL-006-0.
---------------------------------------------------------------------------
1685. The TPL group of Reliability Standards contains a table
designated ``Table 1'' (Transmission System Standards--Normal and
Emergency Conditions), which is a key part of this group of Reliability
Standards. It lays out the system performance requirements for a range
of contingencies grouped according to the number of elements forced out
of service as a result of the contingency. For example: Category A
applies to the normal system with no contingencies; Category B applies
to contingencies resulting in the loss of a single element, defined as
a generator, transmission circuit, transformer, single DC pole with or
without a fault; Category C applies to a contingency resulting in loss
of two or more elements, such as any two circuits on a multiple circuit
tower line or both poles of a bi-polar DC line; while Category D
applies to extreme contingencies resulting in loss of multiple
elements, such as a substation or all lines on a right-of-way. The
system performance expectations for Category C contingencies are lower
than those for Category B contingencies, in that they allow unspecified
amounts of planned or controlled loss of load.
a. General Issues
1686. Commenters raise a number of issues that apply generally to
Reliability Standards TPL-001-0 through TPL-004-0. These issues are
related to the transmission planning process, sensitivity studies and
critical system conditions, element-based versus event-based
contingencies, spares strategy, and resource information for planning
and sharing information with neighboring systems. We address these
general issues here, and the conclusions reached will apply to our
discussion of individual TPL Reliability Standards.
i. Transmission Planning Process
1687. The Commission stated in the NOPR that the Reliability
Standards are not intended to make the Bulk-Power System failure-
proof.\424\ In addition, we did not propose to modify the TPL
Reliability Standards to require that the system be able to withstand
all multiple-contingency and extreme contingency events without loss of
load. Nonetheless, we stated that we believe that the planning-related
Reliability Standards could be improved to better account for probable
contingencies when conducting planning studies. Much of our proposal
was consistent with the potential improvements NERC recognized in its
comments on the Staff Preliminary Assessment. In addition, we noted
that a number of regions currently utilize superior planning practices
that may be characterized as ``best practices'' and are more stringent
than the proposed TPL Reliability Standards.\425\ Accordingly, we
proposed that the ERO submit to the Commission such regional
differences in transmission planning criteria that are more stringent
than those specified in the TPL group of Reliability Standards.
---------------------------------------------------------------------------
\424\ NOPR at P 1042.
\425\ Examples include practices cited in NERC's ``Examples of
Excellence'' found in its Readiness Audits (available at http://www.nerc.com
) and filings for jurisdictional utilities in Part 4 of
FERC Form No. 715, Transmission Planning Reliability Criteria.
Regional reliability organizations also specify requirements that
exceed NERC Reliability Standards, such as WECC's Minimum Operating
Requirement Criteria and the NPCC Document A-02--Basic Criteria for
Design and Operation of Interconnected Power Systems.
---------------------------------------------------------------------------
(a) Comments
1688. EEI and APPA strongly believe that the transmission planning
processes performed under these Reliability Standards have served this
nation extremely well. The Reliability Standards have evolved with
changes in industry structure, computer and
[[Page 16571]]
communications technology, electric generation and transmission
technology and a broad range of state and federal regulatory demands.
EEI and APPA state that it is unclear whether the Commission is
proposing a significant expansion of this reliability planning process,
which would amount to a fundamental shift in the nature of that
process, or whether the Commission is proposing a more specific
description of today's comprehensive planning approach. EEI and APPA
state that they can interpret the Commission's proposal either as
suggesting that planning should support a robust and flexible network
that can ``bend'' to a broad range of critical system conditions, as
practiced up to now, or that planning should be ``finely tuned'' so
that reliability can be maintained under conditions where both
resources and loads are highly controlled. They find the source for the
latter interpretation in the Commission's request that the industry
move toward more explicit requirements that transmission planners
consider the effects of load control or other forms of DSM, or conduct
planning studies for far more combinations of resource alternatives.
EEI and APPA state that the existing Reliability Standards fully meet
the Commission's criteria as set forth in Order No. 672, unless the
Commission envisions a very different transmission system planning
process or seeks to move away from current network design toward the
development of a much ``tighter'' transmission system through
substantially higher saturations of controllable resources and loads.
1689. SDG&E notes that the NOPR's characterization of the dual
objectives of ``appropriateness'' and ``specificity'' speaks, on the
one hand, to the need for Reliability Standards that are tailored to
each transmission planner's area of responsibility, and, on the other
hand, clear, consistent and workable rules. SDG&E urges the Commission
to be mindful of the need to assess and balance these considerations in
future iterations of the transmission planning Reliability Standards.
1690. Northern Indiana states that the presentation of TPL-001-0
through TPL-004-0 as individual Reliability Standards creates a great
deal of confusion. In practice, most transmission planners take an
integrated view of these Reliability Standards and treat them as if
they were a single standard. Accordingly, Northern Indiana suggests
that the Commission ask NERC to file a substitute proposal that would
integrate the transmission planning standards and improve their clarity
and quality.
1691. SDG&E supports the Commission's proposal to direct NERC to
submit for approval regional transmission planning criteria that have
been adopted and extensively used that are more stringent than those
specified in the current TPL Reliability Standards. NCPA states that
whenever a RTO/ISO adopts criteria that differ from ERO or regional
standards, those criteria should be made public and transparent.
(b) Commission Determination
1692. EEI and APPA raise an important question on the Commission's
intent regarding the transmission planning process and proposed
modifications to the transmission planning standards. They ask whether
the Commission is proposing a fundamental shift in the nature of the
planning process that would result in a move away from the current
network design towards a much ``tighter'' transmission system through
substantially increased use of controllable resources and loads. The
Commission is not proposing a fundamental shift in the nature of the
planning process as it is practiced today. We clarify that all the
proposed modifications to the TPL group of Reliability Standards are
aimed at ensuring Reliable Operation of the Bulk-Power System. To
achieve this goal, it is necessary, among other things, to ensure that
the planning process and the Reliability Standards produce a Bulk-Power
System that is robust enough to be able to withstand a range of
probable contingencies while reliably serving customer demand and
preventing the identified outages, and flexible enough to accommodate a
broad range of system conditions over a planning horizon that takes
into account lead times to place facilities in service. Further, the
proposed modifications are intended to ensure that the planning
requirements are specific enough to promote rigor and consistency in
assessments and provide clear and measurable rules for mandatory and
enforceable Reliability Standards. The Commission therefore agrees with
SDG&E's comments in this regard and on the need to balance
``appropriateness'' and ``specificity.''
1693. The Commission agrees with Northern Indiana that the
Reliability Standards TPL-001-0 through TPL-004-0 would be improved if
they were integrated into a single Reliability Standard. Such an
approach conforms more closely to common planning practices, and
integrating these Reliability Standards therefore could enhance their
practical effectiveness. The Commission notes that the Work Plan
submitted by the ERO has earmarked this group of Reliability Standards
for revision during the early stages of the plan. The Commission
directs the ERO to consider integrating Reliability Standards TPL-001-0
through TPL-004-0 into a single Reliability Standard through the
Reliability Standards development process.
1694. The Commission agrees with SDG&E and NCPA that any criteria
that are more stringent than the ERO planning criteria should be made
public and transparent. It is essential that such criteria be
accessible to and understood by the entities to which they apply.
Accordingly, the Commission directs the ERO to submit to the Commission
in an informational filing, in addition to regional criteria, all
utility and RTO/ISO differences in transmission planning criteria that
are more stringent than those specified by the TPL group of Reliability
Standards. We believe that this information will provide us, as well as
the ERO and industry with an indication of the actual transmission
practices utilized in the industry today. This should be used by the
ERO in the Reliability Standards development process.
ii. Sensitivity studies and critical system conditions
1695. The Commission stated in the NOPR that it is not realistic to
expect the ERO to develop Reliability Standards that anticipate every
conceivable critical operating condition applicable to unknown future
configurations for regions with various configurations and operating
characteristics.\426\ The practical solution implemented by many in the
industry is to perform sensitivity studies that define and provide
documentation of the reliability impact on the system. The Commission
therefore stated that it would be appropriate for planning entities to
conduct sensitivity studies to ``bracket'' the range of probable
outcomes. Thus, without having to anticipate ``every conceivable
critical operating condition,'' planning entities will have a means to
identify an appropriate range of critical operating conditions. Both
staff and commenters on the Staff Preliminary Assessment noted that
system conditions are as important as contingencies in evaluating the
performance of present and future systems.
---------------------------------------------------------------------------
\426\ NOPR at P 1047.
---------------------------------------------------------------------------
(a) Comments
1696. Most of the commenters agree with the Commission's proposal
on sensitivity studies to determine critical
[[Page 16572]]
system conditions. These include FirstEnergy, TVA, MidAmerican, Entergy
and SDG&E. However, a few commenters, including EEI, APPA, MISO and
Northern Indiana, take the view that such a requirement is unnecessary
and overly prescriptive.
1697. FirstEnergy states that it is appropriate for the Commission
to require sensitivity analyses, because assessing multiple
sensitivities against a set of system contingencies is prudent system
planning.
1698. TVA agrees that an appropriate range of critical operating
conditions that will ``stress'' the Bulk-Power System needs to be
identified for use in transmission planning. It states that sensitivity
studies should be performed and historic data analyzed to determine the
most probable range of operating conditions that will stress the Bulk-
Power System.
1699. MidAmerican believes that the proposal to require sensitivity
studies to ``bracket'' the range of probable outcomes and determine
critical system conditions is reasonable. It states that, while
critical conditions may be determined in a similar manner for the
different TPL Reliability Standards, different critical conditions are
pertinent to each Reliability Standard. For example, thermal overloads
occur under peak load conditions and dynamic instability occur under
light load conditions.
1700. Entergy does not object to an assessment of critical system
conditions using the factors identified in the NOPR,\427\ but it
contends that the Commission's guidance is problematic to the extent
that it may require constructing facilities to address potential
constraints identified through these assessments. Entergy states that
such construction may not create a desirable result and may instead
threaten reliability. For example, assessing a system using alternative
generation dispatch and transaction patterns could bias a transmission
provider in favor of transmission plans that benefit a specific
generator or set of generators.
---------------------------------------------------------------------------
\427\ Id. at P 1061.
---------------------------------------------------------------------------
1701. SDG&E sees the Commission's treatment of sensitivity studies
and critical system conditions as requiring transmission planning
entities to exercise judgment in determining the scope, content and
number of their sensitivity studies so that they are appropriate given
unique system characteristics and reasonably anticipated contingencies.
SDG&E state that this guidance is welcome and should be reflected in
future Requirements.
1702. MISO agrees that planning entities should have a process to
identify appropriate critical system conditions for planning purposes.
However, it does not believe that the Reliability Standard needs to be
prescriptive in terms of the specific sensitivities that should be
evaluated. If an entity's approach to selecting the critical planning
conditions is appropriate, sensitivities to variations from these
conditions are unnecessary. MISO and Northern Indiana state that
requiring sensitivities in planning studies as a mandatory standard
practice could result in unnecessary additional analysis that could
overwhelm the planning process and detract from more appropriate
focused analysis and evaluation of solutions.
1703. EEI and APPA state that the Commission's proposal on
sensitivity studies would add an unnecessarily redundant process that
ignores the totality of the studies contained in study libraries that
inform planners' decisions. The historical libraries of system studies
provide a strong base for selecting critical transmission system
conditions. EEI believes that the knowledge and experience of planners
who have conducted these studies provides reliable guidance and that a
new array of sensitivity analyses would offer no additional benefit
over existing practices.
1704. Regarding specific variables to be included in sensitivity
studies, EEI and APPA note that load power factors, controllable loads
and DSM at specific locations and outages of reactive devices have much
more to do with distribution operations planning than long-term system
planning. They state that while transmission system planners will study
a broad range of combinations of substation loadings, system
configurations and resource availabilities over the planning horizon,
changes in the variables of the sort identified by the Commission have
very little influence on the long-term study outcomes except for the
loss of load that could occur under extreme circumstances. MISO
believes that transmission reactive power devices should be treated
like any other transmission facility and included in the required
contingency analysis. The current Reliability Standards are not
explicit in this regard, and MISO agrees that this would be an
appropriate clarification. It believes that power factor sensitivity
studies are best suited for operational planning studies rather than
long-term planning since corrective actions have relatively short lead
times. In regard to alternative dispatch scenarios, MISO states that if
a variation from the expected dispatch leads to unacceptable
performance, it becomes an economic planning question, rather than a
planning standard issue, whether expansion should be undertaken or
whether the dispatch becomes a congestion cost.
(b) Commission Determination
1705. In response to Entergy's comments, the Commission reiterates
the statement from the NOPR \428\ that the results of the sensitivity
studies would be used to document the selection of critical system
conditions and study years used in assessing system conditions. The
Commission notes that it is not the purpose of sensitivity studies to
identify remedial actions, but, as stated in the NOPR, if different
scenarios that lead to criteria violations are probable they require
mitigation plans.\429\ Entergy goes on to state that constructing
facilities, the need for which is determined through sensitivity
studies, may not create a desirable result, in that they may bias
transmission plans towards a specific generator or set of generators
and as a result may threaten reliability. The Commission disagrees that
constructing well-planned facilities may threaten reliability. The
planning process should anticipate any inter-regional impacts, and the
net result should be higher local and inter-regional reliability. In
any case, we are not requiring the construction of additional
facilities.
---------------------------------------------------------------------------
\428\ Id. at P 1061.
\429\ Id. at n 324.
---------------------------------------------------------------------------
1706. MISO, EEI, APPA and others question the value of sensitivity
studies and their role in mandatory Reliability Standards given the
knowledge and experience of planners and the historical library of
system studies. The Commission notes that while specificity was not
required in the regime of voluntary standards, it is required in a
regime of mandatory Reliability Standards to ensure consistency in
system assessment and provide clear and measurable requirements.
Further, as stated in the NOPR \430\ and concurred with by commenters
to the Staff Preliminary Assessment, system conditions are as important
as contingencies in evaluating the performance of present and future
systems. Indeed, Table 1 lists the contingencies to be evaluated, but
there is no corresponding requirement for selecting critical system
conditions.
---------------------------------------------------------------------------
\430\ Id. at P 1046.
---------------------------------------------------------------------------
1707. The Commission believes it is important to clarify the type
of analysis
[[Page 16573]]
required in determining critical system conditions, which is the intent
of the directed modifications on sensitivity studies. The Commission
proposed in the NOPR a range of variables to be included in sensitivity
studies, specifically: firm transfers, demand levels, existing and
planned facilities, reactive power resources, control devices, load
power factors, generation retirements, generation dispatch, transaction
patterns, controllable loads, DSM and transmission outages including
outages of reactive power devices.\431\ The Commission also stated that
it is not precluding other approaches to defining and documenting
critical system conditions that have proven to be effective. The
Commission also notes that in analyzing contingencies as part of
Requirement R1.3.1 in Reliability Standards TPL-002-0 through TPL-004-
0, not all contingencies need be assessed for every system element but
only those that would produce the more severe reliability impacts with
documentation of selection rationale. The same applies to the range of
variables specified for sensitivity studies. The Commission expects
that the full range of variables will be considered, but only those
deemed to be significant need to be assessed and documentation provided
that explains the rationale for the selection of variables assessed.
---------------------------------------------------------------------------
\431\ Id. at P 1047.
---------------------------------------------------------------------------
iii. Element-Based vs. Event-Based Contingencies
1708. The Commission stated in the NOPR that planning Reliability
Standards must influence system design and not the other way
around.\432\ To achieve this objective, planning Reliability Standards
should promote system designs that result in the minimum set of
elements being removed from service for ``unanticipated failures of
system elements.'' \433\ The NOPR goes on to say that the Commission
believes that the simulations used in planning assessments should
faithfully duplicate what will happen in the actual power system and
not a generic listing of outages. The Bulk-Power System also must be
operated, and planned to be operated, within a number of conditions
after a contingency or cyber event. The contingency can be a sudden
disturbance or an unanticipated failure of any system element. If a
specific portion of the system has been designed such that the response
to a failure results in multiple lines, transformers, generators,
circuit breakers, etc., being removed from service, the Commission
proposed that this is what should be simulated.\434\
---------------------------------------------------------------------------
\432\ Id. at P 1049.
\433\ Section 215(a) of the FPA defines ``Reliable Operation''
as ``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'' (emphasis added).
\434\ With respect to failure, the element includes a single
transmission line, transformer, generator or single pole of a DC
line.
---------------------------------------------------------------------------
(a) Comments
1709. National Grid, MidAmerican and SDG&E support the principles
set forth in the NOPR. National Grid states that event-based planning
is a more robust form of contingency analysis than element-based
planning because the former focuses on contingencies regardless of how
many elements may be affected while the latter focuses on losses of
specific elements that may not have a direct relationship to the
severity of the impact on or risks to reliability. As such it supports
the Commission's statement that ``simulations should faithfully
duplicate what will happen in the actual power system and not a generic
listing of outages.'' \435\
---------------------------------------------------------------------------
\435\ NOPR at P 1049.
---------------------------------------------------------------------------
1710. MidAmerican states that it supports the Commission's proposal
to interpret a ``single contingency'' to include all elements of the
system, irrespective of their number, that go out of service in
response to failure of a single element, as it has historically
performed this analysis as a part of normal planning in the interest of
reliability. MidAmerican is concerned, however, that this proposal may
be too restrictive for system planning, particularly with regard to the
double contingencies of Category C. It states that if a multi-element
single contingency occurs first, as part of system adjustment, the
reliability coordinator or transmission operator will switch back the
unfaulted elements to service prior to the next contingency. Therefore
this N-1-1 contingency at its worst will consist of a single element
outage followed by a multi-element outage. Therefore MidAmerican states
that the extent of a multiple-element single contingency is better
determined through coordinated efforts of neighboring systems in
conjunction with the planning authority and reliability coordinator.
1711. SDG&E agrees that further modifications to the TPL
Reliability Standards should be guided by the NOPR's directive that
simulations should faithfully duplicate what will happen in the actual
power system and not a generic listing of outages. However, it states
that the Commission should provide further guidance in defining an
event so that planning studies can assess electrical system
contingencies consistently and numerically. A simulation that
faithfully duplicates reasonably expected scenarios will necessarily
involve the transmission planner's sound engineering judgment and
knowledge of elements that would be expected to be removed from service
during the contingency. SDG&E states that the updated TPL Reliability
Standard should reflect and implement these concerns.
1712. EEI believes the planning Reliability Standards and practices
clearly reflect the language in FPA section 215 regarding ``element
based'' planning. Planners study single contingency and multiple
contingency events covering a broad range of system elements and not a
list of generic outages.
1713. TANC recommends that the Commission direct that transmission
planning in the West be based on probability of an event occurring and
the severity of the consequences, rather than on a deterministic
approach that uses single and multiple contingency categories as
exemplified by Table 1. It states that WECC has assessed the
probability of an event occurring for each category and assigned
probabilities accordingly. TANC states that to be more cost effective
and efficient, investments to remedy a problem should be based on a
combination of the probability of the occurrence of the event and the
severity of the associated consequences.
1714. In response to the Commission's request in the NOPR for
comment on whether planning for cyber security events should be
addressed in the planning Reliability Standards or in the Critical
Infrastructure Protection (CIP) Reliability Standards,\436\
MidAmerican, EEI, APPA, ISO-NE and SoCal Edison state they believe that
events requiring study under the CIP Reliability Standards should be
included in that specialized forum rather than the TPL Reliability
Standards. Such events are identified using approaches provided for in
the CIP Reliability Standards. Therefore the best place to explore
those events and determine their impacts using the full background of
the information about the events is the CIP Reliability Standards,
although some of these events will require
[[Page 16574]]
implementation of elements from other Reliability Standards.
---------------------------------------------------------------------------
\436\ Id. at P 1050.
---------------------------------------------------------------------------
1715. National Grid and International Transmission take the view
that cyber security incidents are no different than other events that
remove single or multiple elements from service at a single time and
require analysis of system impacts. Planning assessment for cyber
security incidents therefore is most appropriately addressed in the TPL
Reliability Standards. International Transmission states that although
Table 1 of the TPL Reliability Standards does not list the initiating
event, cyber security events could be included in the list of
contingencies as an initiating event. National Grid cautions that
provisions detailing specific cyber security protections should be
addressed in CIP Reliability Standards, and emergency response
procedures for response to cyber security events should be addressed in
EOP Reliability Standards.
(b) Commission Determination
1716. Several commenters \437\ agree with the Commission's
statement in the NOPR \438\ that ``simulations should faithfully
duplicate what will happen in the actual power system and not a generic
listing of outages.'' It follows that in simulating the failure of a
single element, as required in Category B of TPL-002-0, all of the
elements that are removed from service to isolate the single faulted
element should be modeled in the simulation rather than restricting the
simulation to just the single faulted element, as Table 1 of TPL-002-0
implies. As SDG&E notes, this will require the transmission planner's
sound engineering judgment and knowledge of elements that would be
expected to be removed from service during the single contingency. The
Commission agrees with MidAmerican that for Category C contingencies of
TPL-003-0, the worst N-1-1 contingency would be a single element outage
followed by a multiple element outage, provided that following the
first N-1 contingency, capability exists to switch the unfaulted
elements back into service promptly, i.e., within 30 minutes, as part
of the adjustments that the Reliability Standard allows.
---------------------------------------------------------------------------
\437\ National Grid, MidAmerican and SDG&E.
\438\ NOPR at P 1049.
---------------------------------------------------------------------------
1717. SDG&E agrees that simulations should faithfully duplicate
what will happen in the actual power system and not a generic listing
of outages, but it seeks Commission guidance on how an event should be
defined. In the Commission's view, a single contingency consists of a
failure of a single element that faithfully duplicates what will happen
in the actual system.\439\ Such an approach is necessary to ensure that
planning will produce results that will enhance the reliability of that
system. Thus, if the system is designed such that failure of a single
element removes from service multiple elements in order to isolate the
faulted element, then that is what should be simulated to assess system
performance. Accordingly, the Commission directs the ERO to submit
modifications to Category B of Table 1 consistent with this approach.
Entities whose systems may have been planned and designed on the basis
of a different approach to single contingencies should work with the
ERO in developing plans to transition to this approach.
---------------------------------------------------------------------------
\439\ A ``single element'' means a transmission line, a
transformer, a generator or a single pole of a DC line.
---------------------------------------------------------------------------
1718. The Commission disagrees with EEI that the planning
Reliability Standards and practices clearly reflect the language in FPA
section 215 regarding ``element based'' planning. Section 215(a) of the
FPA defines ``Reliable Operation'' as ``operating the elements of the
Bulk-Power System'' within certain limits so that ``instability,
uncontrolled separation or cascading failures of that system will not
occur as a result of sudden disturbances, including a cyber security
incident, or unanticipated failure of system elements.'' This
definition specifies an ultimate goal and does not dictate any specific
type of planning. The approach to a single contingency the Commission
has set forth above ensures that transmission planners analyze
contingencies based on the actual number of elements that would be
removed from service in the actual power system for ``an unanticipated
failure of system elements,'' rather than simulating only the limited
number of outages listed in Table 1 of the TPL Reliability Standards.
In short, the Commission's approach speaks directly to the problem that
the statute requires be addressed.
1719. In response to TANC's proposal that the Commission direct
that probabilistic approaches to transmission planning be adopted in
the West, the Commission notes that proposals of this type should be
submitted to the ERO for approval as a regional difference. If such a
proposal is developed for the Western Interconnection, to assist the
ERO and the Commission in its assessment of such a proposal, we
encourage WECC to also submit operating information that quantifies the
level of actual performance that has been achieved with the present
deterministic planning approach. Such performance metrics would assist
us in determining whether a probabilistic approach would result in
equivalent or higher levels of Reliable Operation than currently
achieved.
1720. In response to the comments received on how best to address
planning for cyber security events, it is clear that the nature of
risks as well as the contingencies and measures needed to overcome them
are best addressed in the CIP Reliability Standards because this forum
has the specialized knowledge to deal with cyber security matters.
However, the system impacts of cyber security events are best addressed
in the TPL group of Reliability Standards, particularly TPL-004-0,
alongside other similar common mode failures. Emergency plans and
restoration procedures to deal with cyber security events are best
addressed by the EOP Reliability Standards because these Reliability
Standards deal with emergency plans and restoration procedures. The
Commission directs the ERO to consider appropriate revisions to the
Reliability Standards through its Reliability Standards development
process to address these matters.
iv. Spare Equipment Strategy
1721. The Commission stated in the NOPR that while Reliability
Standards TPL-002 through TPL-004 require consideration of planned
outages at those demand levels for which planned outages are performed,
they do not address situations where critical equipment, such as a
transformer or phase angle regulator, may be unavailable for a
prolonged period. Including such a requirement would ensure the
coordination of contingency plans, including the entity's spare
equipment strategy, to return facilities to service in a timely manner
for reliability. The Commission therefore proposed that the Reliability
Standards be modified to include a new requirement to assess the
reliability impact of an entity's existing spare equipment strategy.
(a) Comments
1722. SDG&E states that it generally supports a new requirement
that would include assessing the reliability impact of an entity's
spare equipment strategy, but several key features of this requirement
need clear and thorough definition. For example, the requirement should
provide an industry-developed finite list of ``critical items,'' and
the meaning of ``impact IROL'' would need further clarification. SDG&E
submits that, absent a careful delineation of the requirement and its
[[Page 16575]]
terms, this proposed modification will not enhance system reliability.
1723. MidAmerican, LPPC, EEI, APPA and SoCal Edison state that they
understand the Commission's concern about spare equipment planning and
acquisition strategy. However, MidAmerican and LPPC note that typically
spare equipment strategy is of more concern in operating studies than
planning studies. MidAmerican states that most equipment can be
installed in a year or less even if it is not on hand. It maintains
that it may be appropriate to add this requirement to the TPL
Reliability Standards because scarcity of new equipment due to recent
disasters has led to longer lead times. LPPC cautions the Commission
that associating spare equipment strategy with the planning Reliability
Standards could lead to Reliability Standards that overstep the limits
of FPA section 215(i)(2) through proposing a Reliability Standard that
would, indirectly, come close to authorizing the ERO to order the
construction of transmission capacity. LPPC states that it is unclear
how to separate: (1) Requiring a utility to assess its spare equipment
strategy; (2) requiring a utility to have spares on hand to meet
anticipated reliability needs and (3) requiring a utility to use spare
equipment to meet the reliability needs.
1724. EEI, APPA and SoCal Edison question the need to address this
issue in the context of a Reliability Standard. EEI states that, where
delivery delay could occur for long lead time equipment such as
transformers, the existing Reliability Standards provide for study of
the full range of single and multiple-event contingencies with that
piece of equipment modeled off-line. According to EEI, the Commission's
general concern regarding the current policies and practices related to
equipment acquisition can be addressed in the NERC forum without
revising the Reliability Standards. This forum also will account for
the need to protect information on critical infrastructure facilities.
(b) Commission Determination
1725. Several commenters stated that they understand the
Commission's concern about requiring a reliability impact assessment of
an entity's spare equipment strategy, but they question the need to
address this issue in the Reliability Standards in general and the
transmission planning Reliability Standards in particular. The
Commission disagrees with EEI that the existing Reliability Standards
provide for situations that cover the delivery of long lead time
equipment, such as transformers, by requiring a full range of single
and multiple contingency studies with that equipment modeled off-line.
TPL-002-0 and TPL-003-0 currently state explicitly in Requirement
R1.3.12 that the assessments shall include planned outages of bulk
electric equipment at those demand levels for which planned (including
maintenance) outages are performed. However, equipment such as
transformers may not be available for service for a year or more and
therefore their unavailability cannot be scheduled when system
conditions permit.
1726. The current Reliability Standards do not require assessment
of the reliability impacts that result from not having this long lead
time equipment available under those system conditions likely to be
experienced during the course of the year when the system is heavily
stressed. Clearly the consideration of planned outages is inextricably
linked with spare equipment strategy. Thus, if an entity's spare
equipment strategy for the permanent loss of a transformer is to use a
``hot spare'' or to relocate a transformer from another location in a
timely manner, the outage of the transformer need not be assessed under
peak system conditions. However, if the spare equipment strategy
entails acquisition of a replacement transformer that has a one-year or
longer lead time, then the outage of the transformer must be assessed
under the most stressed system conditions likely to be experienced.
Accordingly, the Commission directs the ERO to modify the planning
Reliability Standards to require the assessment of planned outages
consistent with the entity's spare equipment strategy.
1727. LPPC questions whether the Commission's proposal oversteps
the limits of FPA section 215(i)(2) because assessing the impact on
reliability of an entity's decision concerning spare equipment could
force an entity to construct transmission capability. FPA section
215(i)(2) prohibits the ERO and the Commission from ordering the
construction of ``additional'' transmission capacity. A requirement to
assess the reliability impacts of an entity's spare equipment strategy
is no different than a requirement to assess the reliability impacts of
any number of contingencies. Even if an entity was forced to conclude
that its spare strategy was inadequate, rectifying the problem would
not require that the entity construct ``additional'' transmission
capacity, only that it possess adequate spares, or take other
appropriate action, to ensure the reliable operation of its system. In
short, while FPA section 215(i)(2) precludes ordering expansion of
transmission or generation capacity, section 215 clearly authorizes
requiring entities to take appropriate steps to ensure that their
existing capacity operates reliably.
1728. With regard to SDG&E's suggestion to clarify specific
elements of this Reliability Standard, we direct the ERO to consider
such suggestions in its Reliability Standards development process.
v. Resource Information for Planning
1729. The Commission in the NOPR requested comments on whether
transmission planners and planning authorities are currently able to
obtain and validate resource information on new generation and
retirements for assessments over the ten year planning horizon.
Further, if transmission planners and planning authorities currently
experience difficulty obtaining this information, the Commission asked
how this potential information gap should be addressed.\440\
---------------------------------------------------------------------------
\440\ NOPR at P 1060.
---------------------------------------------------------------------------
(a) Comments
1730. The Commission noted in the NOPR that transmission planning
requires information on forecasted loads and probable generation plans
to supply those loads.\441\ While the MOD Reliability Standards require
information on forecasted loads, energy, interruptible loads and direct
control load management over the next ten years, there is no
requirement to inform transmission planners and planning authorities of
new or retiring generation resources. The Commission sought comments on
whether transmission planners and planning authorities are currently
able to obtain and validate resource information on new generation and
retirements for assessments over the ten year planning horizon and if
not, how this potential gap should be addressed.
---------------------------------------------------------------------------
\441\ Id.
---------------------------------------------------------------------------
1731. NERC stated that it and the regional reliability
organizations have generally not had problems obtaining the data and
information required for reliability assessments. NERC believes that
given its authority and responsibility as the ERO, it will be
successful in obtaining all the data and information it needs to
conduct reliability assessments without the need to include these
requirements in Reliability Standards. In the event that it and the
regional reliability organizations are unsuccessful in obtaining such
data and information,
[[Page 16576]]
the ERO will turn to the Commission for assistance.
1732. ISO-NE states that as the planning authority it obtains
resource plans for additions, capacity changes, deactivations and
retirements for a ten year planning horizon. Although these plans
cannot be expected to occur exactly as projected, they serve as useful
information in projecting needs for new resources or new or upgraded
transmission facilities. As the administrator of wholesale electric
markets, ISO-NE relies on the development of robust market rules
accompanied by a regulated transmission planning process to achieve its
goal of encouraging the availability of sufficient resources. ISO-NE
states that planning for the introduction and retirement of specific
resources ten years in advance not only is unnecessary, it is
inconsistent with relying on markets to determine the most efficient
allocation of resources to meet system needs.
1733. FirstEnergy and SoCal Edison state that currently they are
able to obtain information regarding new generation from publicly
available information and from the generator interconnection queue.
Typically, a generation application that is in the interconnection
agreement phase is considered for transmission planning studies. New
generation has a longer lead time, and thus information on it may be
available sooner than information about retirements, which have a much
shorter lead time before they are announced. FirstEnergy states that
despite the unpredictability of such information, assessments can be
conducted using assumptions of new generation and retirements, and the
results should recognize that the inputs were based on reasonably
foreseeable conditions.
1734. In contrast, CAISO, National Grid and Northern Indiana state
that obtaining resource information has been a challenge given that the
Reliability Standards impose no obligation on generation owners to
provide information to planning authorities and transmission service
providers about new and retiring generation. Northern Indiana states
that this issue is among the greatest challenges for its transmission
planners. Because transmission planning is focused on matching the
source to the sink, having the sources unknown, in the case of future
generation, creates a weakness in the entire transmission planning
process. Northern Indiana contends that weakness will be difficult to
eliminate because information about siting of future generation units
is considered commercially sensitive information. This lack of
information makes it difficult for transmission planners to reflect
accurately the amount and location of new generation in their
transmission studies. CAISO agrees that there is a gap in its ability
to obtain this information particularly from adjacent balancing
authorities. CAISO suggests that to bridge this gap, generator owners
and operators should be required to provide data about new and retiring
generation to their planning authorities and that the planning
authorities be required to share this information with neighboring
balancing authorities, subject to appropriate non-disclosure
agreements. CAISO notes that there currently exists no centralized
database for the collection and dissemination of this information
within the Western Interconnection.
1735. National Grid states that forward capacity markets and the
generation interconnection queue provide some understanding about new
generation but only for five to seven years, even though transmission
planning horizons are considerably longer. National Grid and Northern
Indiana contend that it may be reasonable to conclude that certain
areas are prime locations for new resources, particularly inexpensive
and renewable resources that are dependent on ``non-transportable''
fuel supplies. National Grid states that the Commission should embrace
efforts of transmission planners to facilitate new generation entry
when such initiatives are expected to increase customer access to
inexpensive, renewable and diverse sources of supply.
1736. Entergy believes that from a transmission provider's point of
view it would be desirable to have LSEs provide ten or even five-year
resource forecasts. Entergy recognizes that such a requirement may not
be practical when LSEs depend significantly on short-term purchases due
to the abundance of independent power producers or in areas that have
an locational marginal pricing-like market structure. MISO states that
its experience suggests that LSEs do not identify new generation
resources except in very general terms past the second or third year.
In most cases LSEs show future capacity requirements served from
generic base load and peaking power resources or from potential
contract purchases with no information on location. This increases the
difficulty of accurate long-range transmission planning studies.
1737. National Grid states that it is also vitally important to
acknowledge that generation retirements may pose a greater threat to
reliability in some areas of the country than the slow down of new
generation. Because required notice periods for retirements may be as
little as ninety days in some areas, it is imperative that transmission
planners use a robust statistical approach to identify vulnerable
sources of generation and conduct such modeling as an integral part of
the transmission planning process.
1738. MISO states that planning assumptions around generation
retirements are particularly difficult because such assumptions are
driven by complex economic factors that may or may not prevail. While
MISO has the tools to project what unit may be more likely to retire
than others, it contends that the preferred approach is to have in
place tariff provisions that require suppliers to announce retirement
intentions six months in advance of the retirement. This permits
reliability studies to be performed with certainty and corrective
actions to be implemented that could include placing the unit on
contract to continue operations until appropriate operating measures or
system expansions can be made.
1739. SoCal Edison states that business decisions by generator
owners to retire or mothball units are outside of SoCal Edison's
control, and generally SoCal Edison does not receive this information
in a timely manner for transmission planning studies.
1740. National Grid urges the Commission to support longer planning
horizons. It states that in many respects, the ten year planning
horizon may be too short a time frame for assessing transmission needs,
particularly with regard to long distance extra high voltage facilities
that pose considerable siting and permitting challenges. Establishing
planning horizons that are shorter than transmission construction lead
times may create gaps where the identification of a reliability need to
which transmission may be the best solution occurs too late to head off
the identified reliability violation. National Grid states that PJM is
establishing a fifteen year planning horizon that will accommodate
large-scale projects that are needed for reliability and to support
regional transactions.
1741. MISO and International Transmission note that while it is
important for planners to have quality information on available
resources, the enabling legislation for the ERO specifically excludes
authority regarding resource adequacy. MISO states it is not certain
how far the Reliability Standards can go. International Transmission
states that, in the absence of a standard on resource
[[Page 16577]]
adequacy, transmission service providers must use their judgment on
potential new generation or retirements to create base cases and plan
the system accordingly.
1742. Reliant states that, while section 215 of the FPA requires
the ERO to develop Reliability Standards that provide an adequate level
of Bulk-Power System reliability, the proposed Reliability Standards
surprisingly lack any substantive consideration of planning reserve
obligations to ensure capacity available to meet the needs of a
reliable system. Reliant proposes that each regional reliability
organization develop and enforce its own minimum planning reserve
margin. Such a program would be critical to the development of new
generation, demand response and distributed generation resources and
allow each region to retain its own autonomy in developing its own
resource adequacy standards.
1743. Process Electricity Committee supports long-term planning as
a vital part of any economic and thorough set of Reliability Standards.
However, it is concerned that transmission service providers who are
also market participants will have an incentive to exploit commercially
sensitive data on generation plans to the disadvantage of other
competing suppliers. Process Electricity Committee asks the Commission
to clarify that transmission planners may not use the Reliability
Standard to obtain and exploit such information, and it urges the
Commission to take all appropriate measures to guard against such
abuse.
(b) Commission Determination
1744. Several commenters addressed separately the availability of
information on new generation resources and generation retirements,
given that these have very different lead times. NERC, ISO-NE and
others appear to be able to acquire the resource information they need
on new resources and retirements for reliability assessments. Others,
such as National Grid and MISO, have had difficulty in obtaining this
information in a timely manner, particularly as it relates to
generation retirements.
1745. The Commission disagrees with ISO-NE's statement that
planning for the introduction of resources ten years in advance is not
necessary. The existing Reliability Standard requires that the planning
horizon must take into account the lead times for siting and permitting
of new long-distance transmission lines and other solutions that can
exceed ten years. In short, the need for long-term planning has already
been widely recognized. The Commission agrees with National Grid that
establishing planning horizons that are shorter than transmission lead
times may create gaps where the identification of a reliability need to
which transmission may be the best solution occurs too late to avert
the identified reliability violation. Indeed, this point is supported
by the fact that PJM is establishing a fifteen year planning
horizon.\442\
---------------------------------------------------------------------------
\442\ See http://www.pjm.com/contributions/pjm-manuals/manuals.html
.
---------------------------------------------------------------------------
1746. In the absence of information about future generation
resources required for transmission planning the Commission notes that
entities conduct assessments using assumptions based on the knowledge
that certain areas are prime locations for new resources, particularly
those resources that use non-transportable fuels. National Grid states
that generation retirements may pose a greater threat to reliability in
some areas than the slowdown of new generation construction. As a
result, it states that it is imperative that transmission planners use
robust statistical approaches to identify vulnerable sources of
generation and conduct such modeling as an integral part of the
transmission planning process. The Commission understands this as a
further endorsement of its proposal to require a full range of
sensitivity studies discussed above.
1747. MISO, International Transmission and Reliant raise important
issues about the absence of a Reliability Standard on resource
adequacy. Reliant points out the inconsistency between the statutory
requirement to provide an adequate level of Bulk-Power System
reliability and the lack of any substantive consideration of planning
reserve obligations to ensure capacity is available to meet the needs
of a reliable system. In the same vein, the Commission notes that
Requirement R7 of TOP-002-0 requires each balancing authority to plan
to meet capacity and energy reserve requirements in the operating time-
frame but that there is no explicit corresponding consideration
required of generation reserves in the planning time-frame.
1748. Section 215(a)(3) of the FPA makes clear that enforceable
Reliability Standards may not address requirements to enlarge
facilities or construct new generation capacity. We have noted that
when a state or appropriate jurisdictional entity has such a
requirement, it should be included in transmission planning analysis.
Resource adequacy levels are set to achieve a number of goals, one of
which is system reliability. Our jurisdiction is to approve and enforce
Reliability Standards that provide for an adequate level of reliability
for the Bulk-Power System. The TPL group of Reliability Standards
includes load growth, changes in the transmission topology, existing
generation, generation retirements, and confirmed new generation as
inputs to the analyses. When an entity does not meet a reliability
criterion, including the inability of generation to be deliverable to
load, mitigation plans are required. Although the Commission
anticipates that some of those mitigation plans may include new
generation, we do not require this.
1749. Some entities have proposed possible solutions to address the
gap of inadequate and unreliable resource information for long-term
planning as required by the TPL group of Reliability Standards. CAISO
suggests that generator owners and operators be required to provide
data on new generation and retirements to their planning authorities.
Entergy proposes requiring LSEs to provide this information, but
recognizes that this approach has its limitations. MISO contends the
preferred approach to retirements is to have in place tariff provisions
that require suppliers to announce retirement intentions six months in
advance of retirements. Process Electricity Committee is concerned
about the implications of sharing non-public transmission or customer
information which could then be exploited to the disadvantage of
competing suppliers. The Commission's Standards of Conduct addresses
the sharing of such information and generally prohibits the sharing of
commercially sensitive information between the transmission
organization and affiliated merchant functions.\443\ In response to
Process Electricity Committee, the Commission will continue to enforce
the information sharing prohibition in the Standards of Conduct.
---------------------------------------------------------------------------
\443\ See Order No. 2004.
---------------------------------------------------------------------------
1750. The responses to the Commission's inquiry on these matters
are helpful. The comments further point out the importance of
conducting a wider range of sensitivity studies on generation
scenarios. However, the Commission is not directing at this time any
modifications to address the Commission's concerns.
[[Page 16578]]
vi. Sharing of Information With Neighboring Systems
1751. In the NOPR, the Commission stated that, because neighboring
systems may be adversely impacted, such systems should be involved in
determining and reviewing system conditions and contingencies to be
assessed in connection with Requirement R1.3 of TPL-001-0 to TPL-004-
0.\444\
---------------------------------------------------------------------------
\444\ NOPR at P 1063.
---------------------------------------------------------------------------
(a) Comments
1752. EEI, APPA, FirstEnergy, ERCOT and SDG&E support or
acknowledge the value of sharing of various kinds of planning
information with neighboring systems. FirstEnergy states that the
proposed requirement that system conditions and contingencies assessed
be shared and reviewed by neighboring systems will improve
communications with interconnected companies. This process was
established among former ECAR companies through the ``ECAR Peer Review
Process,'' and FirstEnergy recommends that regional reliability
organizations be encouraged to establish a similar process going
forward. EEI and APPA state that sharing of various kinds of planning
information, including expected generation additions and retirements,
planned outages, demand forecasts and estimates of firm transfers will
go a long way to improving the quality and consistency of planning
study efforts. However, it is not clear to EEI whether a formal
Reliability Standard would be the most effective approach. An
alternative could be to request that NERC oversee an informal process
to explore alternatives and report back to the Commission by a specific
date. Although ERCOT states that this proposal is a sensible
recommendation, it also states that it would not be appropriate for
ERCOT since the transmission service provided there is not subject to
interruption by the ISO, and outbound flows are also not interrupted if
there is a shortage of capacity.
1753. SDG&E notes that under the auspices of the CAISO it regularly
convenes stakeholder meetings with the general public, neighboring
utilities, generator owners, regulators and the CAISO. In these
meetings, SDG&E reviews the grid assessment process and receives
comments from participants about all aspects of its process. As a
member of WECC, SDG&E states that it also holds meetings to discuss
inter-area projects that SDG&E has proposed to construct. This review
group consists of neighboring utilities, generator owners and other
stakeholders who are members of WECC. Similarly, SDG&E maintains that
it participates in other California-based utility review groups. SDG&E
finds that these existing processes provide ample opportunities for
regular sharing of relevant information with neighboring transmission
planning entities. It thus recommends that the Reliability Standards
development process take into account existing forums for apprising
neighboring utilities of current and anticipated transmission planning
issues and projects. If the Commission believes additional
communications are needed, SDG&E strongly recommends that the
Commission, through NERC or the applicable Regional Entity, specify in
greater detail the nature and periodicity of the information to be
shared pursuant to the TPL Reliability Standards.
1754. SoCal Edison states that TPL-001-0 is for systems operating
under normal conditions, and as such there should not be a need for any
review by neighboring systems.
(b) Commission Determination
1755. Most commenters agree with the Commission's proposal that
neighboring systems be involved in a peer review of system assessments
in connection with Requirement R1.3 of TPL-001-0 through TPL-004-0.
Given that neighboring systems assessments by one entity may identify
possible interdependent or adverse impacts on its neighboring systems,
this peer review will provide an early opportunity to provide input and
coordinate plans. The Commission therefore disagrees with SoCal
Edison's view that there is no need for any review by neighboring
systems for TPL-001-0. For example, the planning authorities needs to
be consistent in the line flow values that they use.
1756. While supporting the concept of a peer review, EEI questions
whether making this a Requirement in a Reliability Standard is the most
effective approach or whether NERC should explore alternatives and
report to the Commission by a specific date. The Commission sees no
reason why peer reviews should not be part of a Reliability Standard
since TPL-001-0 through TPL-004-0 already include in Requirement R1.3 a
review of assessments by the associated regional reliability
organization. The Commission understands that some regions include peer
review as part of their procedures. Accordingly, to ensure that
neighboring systems are not adversely affected and to provide an early
opportunity for input and coordination of plans, the Commission directs
the ERO to include these modifications to the Reliability Standard
through its Reliability Standards development process to provide for
the appropriate sharing of information with neighboring systems.
1757. The Commission has taken action on its OATT reform initiative
in Order No. 890. In that order, the Commission encourages the
formation of regional planning processes and economic planning
studies.\445\ Sharing of information and peer review are the first
steps in a regional planning process. The Commission provides guidance
and direction on these subjects in our discussion of Reliability
Standard TPL-005-0.
---------------------------------------------------------------------------
\445\ Order No. 890 at P 526, 542.
---------------------------------------------------------------------------
b. System Performance Under Normal (No Contingency) Conditions (TPL-
001-0)
1758. Reliability Standard TPL-001-0 deals with planning related to
system performance under normal conditions, i.e., a situation where no
system contingency or no unexpected failure or outage of a system
component has occurred.\446\ The Reliability Standard seeks to ensure
that the Bulk-Power System is planned to meet the system performance
requirements under these normal conditions by requiring the
transmission planner and the planning authority to evaluate their
transmission system annually and document the ability of that system to
meet the performance requirements established in the Reliability
Standard under conditions where no system contingencies are
present.\447\ Meeting these requirements means two things. First, when
all system facilities are in service and normal operating procedures
are in effect, the system can be operated to supply projected customer
demands and projected firm (non-recallable reserved) transmission
services at all demand levels over the range of forecast system
demands. Secondly, the system remains stable and within the applicable
ratings for thermal and voltage limits, no loss of demand or curtailed
firm transfers occurs, and no cascading outages occur. TPL-001-0
applies both to near-term and longer-term planning horizons.
---------------------------------------------------------------------------
\446\ The NERC Glossary defines a ``contingency'' as ``[t]he
unexpected failure or outage of a system component, such as a
generator, transmission line, circuit breaker, switch or other
electrical element.'' NERC Glossary at 3.
\447\ The performance requirements are set forth in Category A
of Table I of the Reliability Standard.
---------------------------------------------------------------------------
1759. The Requirements of TPL-001-0 specify that the planning
authority and transmission planner must
[[Page 16579]]
demonstrate through a valid assessment that the Reliability Standard's
system performance requirements can be met. The assessment must be
supported by a current or past study and/or system simulation testing
that addresses various categories of conditions to be simulated as set
forth in the Reliability Standard to verify system performance under
normal conditions. When system simulations indicate that the system
cannot meet the performance requirements set forth in the Reliability
Standard, a documented plan to achieve system performance requirements
must be prepared. The specific study elements selected from each of the
categories for assessments are subject to approval by the associated
regional reliability organization.
1760. The Commission proposed in the NOPR to approve Reliability
Standard TPL-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 proposed to direct NERC to submit a modification to TPL-001-0 that:
(1) Requires that critical system conditions be determined by
conducting sensitivity studies; (2) requires that system conditions and
contingencies assessed be reviewed by neighboring systems; (3) modifies
Requirement R1.3 to substitute the reference to regional reliability
organization with Regional Entity; (4) requires consideration of
planned outages of critical equipment; and (5) modifies footnote (a) of
Table 1 to not apply emergency ratings to compare stresses on the
system under normal conditions as recommended by the Transmission
Issues Subcommittee of the NERC Planning Committee \448\ and require
that normal facility ratings be in accordance with Reliability Standard
FAC-008-1 and that normal voltages be in accordance with Reliability
Standard VAR-001-1.\449\
---------------------------------------------------------------------------
\448\ See NERC Transmission Issues Subcommittee Report:
Evaluation of Criteria, Methods and Practices Used in System Design,
Planning and Analysis in Response to NERC Blackout Recommendation
13c. Appendix B, November 28, 2005.
\449\ NOPR at P 1065-67.
---------------------------------------------------------------------------
i. Comments
1761. APPA agrees with the Commission that TPL-001-0 is sufficient
for approval as a mandatory and enforceable standard.
1762. MidAmerican and others generally support the Commission's
proposal to improve TPL-001-0 but caution that: (1) Planned outages
should only be considered at load levels and conditions under which
they commonly occur and (2) emergency ratings should recognize the
varying timeframes of overloads that result from various contingency
events. Further, MidAmerican states that, while it is appropriate that
planning margins for normal voltages be calculated in accordance with
VAR-001-1 as proposed by the Commission, it would be better if the
proposed modification provided that voltage criteria do not conflict
with VAR-001-1. Northern Indiana agrees with the Commission's position
regarding consideration of planned outages and states that it considers
them currently in its transmission planning studies. International
Transmission states that both planned outages of critical equipment and
the extended forced outages of similar equipment should be considered.
FirstEnergy states that planned outages should be accounted for at load
levels and conditions under which they commonly apply.
1763. Other commenters disagree that planned outages of critical
equipment should be included in TPL-001-0.\450\ They contend that the
Reliability Standard has a very simple aim, namely, to examine whether
a system can perform under normal system intact conditions, i.e., when
all elements are in service and operating as expected. The outages
contemplated are appropriate for TPL-002-0 through TPL-004-0 where the
planned outage could be a line outage caused by a maintenance project
that extends into a period where the system is heavily loaded. SDG&E
states that for near-term planned outages, the transmission planning
entity should retain an appropriate amount of latitude to plan the
outage's timing and details and to modify them as necessary. SDG&E
comments that, for outages planned with a more distant horizon (one
year or longer), this information can be accounted for in sensitivity
analyses. SoCal Edison states that no information will be available
about planned outages of critical equipment to be used for short-term
(five years) or long-term (10 years) simulations. It may be possible to
consider planned outages of critical equipment if there is a major
project construction activity. If generators and transmission lines are
out for scheduled maintenance during off-peak load conditions, then
these outages should be considered.
---------------------------------------------------------------------------
\450\ See, e.g., EEI, APPA, SDG&E, Entergy, SoCal Edison and
TVA.
---------------------------------------------------------------------------
1764. EEI supports the Commission's recommendation to modify
footnote (a) in Table 1. International Transmission states that the
footnotes in Table 1 are not footnotes but rather requirements for
transmission system performance. These should be made requirements of
the Reliability Standards so that they are more obvious and easier to
monitor. APPA, LPPC and TANC recommend that changes to footnotes of
Table 1 be subject to the Reliability Standards development process.
They state that the footnotes have been extensively reviewed by
technical experts at NERC for several years and currently represent a
general consensus among these industry technical experts. Changes to
the footnotes impact Table 1 and have a direct impact on the
determination of the severity of consequences that were approved along
with the original Reliability Standard. Therefore, the Commission
should give due weight to the ERO and allow the Reliability Standards
development process to resolve any existing ambiguities in the Table 1
footnotes.
ii. Commission Determination
1765. The Commission approves TPL-001-0 as a mandatory and
enforceable Reliability Standard. In addition, we direct the ERO to
develop modifications to TPL-001-0 through the Reliability Standards
development process, as discussed below.
1766. In assessing system conditions, Requirement R1.3.1 of TPL-
001-0 requires entities to cover ``critical system conditions and study
years,'' as deemed appropriate by the entity performing the study. As
stated in the NOPR, system conditions are as important as contingencies
in evaluating the performance of present and future systems,\451\ and
yet TPL-001-0 does not specify the rationale for determining critical
system conditions and study years. Consistent with our discussion of
the issue above regarding sensitivity studies and critical system
conditions, the Commission concludes that proposed modification (1),
which requires that critical system conditions be determined by
conducting sensitivity studies, is justified. Accordingly, we direct
the ERO to modify the Reliability Standard to require that critical
system conditions and study years be determined by conducting
sensitivity studies with due consideration of the range of factors
outlined above.
---------------------------------------------------------------------------
\451\ NOPR at P 1046.
---------------------------------------------------------------------------
1767. Requirement R1.3 of TPL-001-0 states that the planning
authority and transmission planner must provide studies and simulations
to support its planning assessments, and that the specific elements
selected for the study shall be acceptable to the associated regional
reliability organization. Given that neighboring systems may be
[[Page 16580]]
adversely affected, our goal is to ensure that they are involved in the
determination and review of system assessments to permit an early
opportunity to provide input and coordinate plans. We discussed above
the issue of information sharing as it applies to the TPL group of
Reliability Standards generally and, consistent with our conclusions
there, we direct the ERO to modify TPL-001-0 to require a peer review
of planning assessments with neighboring entities.
1768. The Commission received no comments on its proposal that
Requirement R1.3 be modified to substitute the reference to the
regional reliability organization with a reference to the Regional
Entity. The Commission has explained the need for this modification
above, and therefore it directs the ERO to modify Requirement R1.3 of
TPL-001-0 to substitute the reference to the regional reliability
organization with a reference to the Regional Entity.
1769. While some commenters support the consideration of planned
outages at load levels for conditions under which they are performed,
others disagree on the grounds that the goal of TPL-001-0 is to ensure
that the Bulk-Power System can perform reliably when all elements are
in service and operating as expected. The Commission notes that
Reliability Standards TPL-002-0 through TPL-004-0 include consideration
of planned outages, as initial system conditions, at load levels for
conditions under which they are performed. Because these Reliability
Standards, and not TPL-001-0, will govern the adequacy of the Bulk-
Power System under planned outage conditions, the Commission will not
adopt the NOPR proposal to require consideration of planned outages at
load levels for conditions under which they are performed for
Reliability Standard TPL-001-0. However, consistent with our discussion
above on spare equipment strategy, the Commission directs a
modification to this Reliability Standard to require assessments of
outages of critical long lead time equipment, consistent with the
entity's spare equipment strategy. Thus, for example, if an entity's
spare equipment strategy for the permanent loss of a transformer is to
use a ``hot spare'' or to relocate a transformer from another location
in a timely manner, the outage of the transformer need not be assessed
under peak system conditions. However, if the spare equipment strategy
entails acquisition of a replacement transformer that has a one-year or
longer lead time, then the outage of the transformer must be assessed
under peak loading conditions likely to be experienced. This approach
will ensure that system conditions are adequately assessed.
1770. While commenters generally agree with the Commission's
proposal to modify footnote (a) of Table 1, they caution that any
changes to the footnotes affect Table 1 and should be reviewed through
NERC's Reliability Standards development process. International
Transmission states that the footnotes in Table 1 are not footnotes but
rather requirements for transmission system performance and therefore
should be made Requirements in the Reliability Standard. The Commission
agrees with International Transmission because this will promote
clarity in and consistent application of the Reliability Standard. The
Commission therefore directs the ERO to modify the Reliability Standard
to address the concerns regarding footnote (a) of Table 1, including
the applicability of emergency ratings and consistency of normal
ratings and voltages with values obtained from other Reliability
Standards. As with any modification to a Reliability Standard,
modifications to TPL-001-0 should be developed through the ERO's
Reliability Standards development process.
1771. Accordingly, the Commission approves Reliability Standard
TPL-001-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-001-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions and study years be determined by conducting
sensitivity studies with due consideration of the range of factors
outlined above; (2) requires a peer review of planning assessments with
neighboring entities; (3) modifies Requirement R1.3 to substitute the
reference to regional reliability organization with Regional Entity;
(4) requires assessments of outages of critical long lead time
equipment, consistent with the entity's spare equipment strategy; and
(5) address the concerns regarding footnote (a) of Table 1, including
the applicability of emergency ratings and consistency of normal
ratings and voltages with values obtained from other Reliability
Standards and the concerns raised by International Transmission in
regard to the footnotes in Table 1.
c. System Performance Following Loss of a Single Element (TPL-002-0)
1772. Reliability Standard TPL-002-0 addresses system planning
related to performance under contingency conditions involving the
failure of a single element with or without a fault, i.e., the
occurrence of an event such as a short circuit, a broken wire or an
intermittent connection. The Reliability Standard seeks to ensure that
the future Bulk-Power System is planned to meet the system performance
requirements, with the loss of one element, by requiring that the
transmission planner and planning authority annually evaluate and
document the ability of the transmission system to meet the performance
requirements where an event results in the loss of a single
element.\452\ Meeting these requirements means two things. First, it
means that the system can be operated following the event to supply
projected firm customer demands and projected firm (non-recallable
reserved) transmission services at all demand levels over the range of
forecast system demands. Second, it means that the system remains
stable and within the applicable ratings for thermal and voltage
limits, no loss of demand or curtailed firm transfers occurs, and no
cascading outages occur.\453\ The Reliability Standard applies both to
near-term and longer-term planning horizons.
---------------------------------------------------------------------------
\452\ The performance requirements are set forth in Category B
of Table 1 of the Reliability Standard.
\453\ Footnote b to Table 1 allows for the interruption of firm
load for consequential load loss.
---------------------------------------------------------------------------
1773. TPL-002-0 specifies that the planning authority and
transmission planner must demonstrate through a valid assessment that
the Reliability Standard's system performance requirements can be met.
The assessment must be supported by a current or past study and/or
system simulation testing that addresses various categories of
conditions to be simulated, as set forth in the Reliability Standard,
to verify system performance under contingency conditions involving the
failure of a single element with or without a fault. The Reliability
Standard requires that planned outages of transmission equipment be
considered for those demand levels for which planned outages are
performed. When system simulations indicate that the system cannot meet
the performance requirements stipulated in the Reliability Standard, a
documented plan to achieve system performance requirements must be
prepared. The specific study elements selected from each of the
categories for assessments are subject to approval by the associated
regional reliability organization.
1774. The Commission proposed in the NOPR to approve Reliability
Standard TPL-002-0 as mandatory and
[[Page 16581]]
enforceable. In addition, pursuant to section 215(d)(5) of the FPA and
Sec. 39.5(f) of our regulations, we proposed to direct NERC to submit
a modification to TPL-002-0 that: (1) Requires that critical system
conditions be determined in the same manner as proposed for TPL-001-0;
(2) requires the inclusion of the reliability impact of the entity's
existing spare equipment strategy; (3) explicitly requires all
generators to ride through the same set of Category B and C
contingencies as required for wind generators in Order No. 661; (4)
requires documentation of load models used in system studies and
supporting rationale for their use; (5) clarifies the phrase ``permit
operating steps necessary to maintain system control'' and (6)
clarifies footnote (b) to Table 1 to allow no firm load or firm
transactions to be interrupted except for consequential load loss.
i. Comments
1775. APPA agrees that TPL-002-0 is sufficient for approval as a
mandatory and enforceable reliability standard.
1776. In response to the Commission's proposal \454\ that NERC
modify TPL-002-0, in part, because it does not address situations in
which critical equipment may be unavailable for a prolonged period,
Northern Indiana states that systems depicted in planning studies
cannot possibly contain complete planned and forced outage schedules
for the next ten years. For this reason TPL-003-0 deals with double
contingencies, i.e., contingencies that allow operator intervention
after the first outage, and then capture system response to an
additional outage. Operator intervention includes coordination of
contingency plans and may impact strategies for spare equipment,
particularly for critical equipment.
---------------------------------------------------------------------------
\454\ NOPR at P 1081.
---------------------------------------------------------------------------
1777. EEI and MidAmerican support requiring all generators to ride
through the same contingencies as required for wind generators.
Constellation notes that while it supports the Commission's proposed
modifications to TPL-002-0, an explicit requirement that all generators
stay online during the same set of Category B and C events, as is
required for wind generators, is too broad. Constellation requests that
the Commission modify this requirement to recognize that NRC has
specific requirements for how nuclear generation must respond to
disturbances on the Bulk-Power System, and that those NRC rules should
apply. Moreover, Constellation generally recommends that the
Reliability Standards applied to nuclear generation should be
consistent with NRC requirements and that NRC rules should control in
the event of conflict.
1778. NRC notes that there appears to be significant variation in
the interpretation of this Reliability Standard. It states that some of
its licensees interpret the TPL-002-0 Reliability Standard to state
that if a licensee is operating in an N-1 condition another single
contingency does not need to be considered. NRC states that its
interpretation has been that the N-1 condition is always analyzed from
the conditions being experienced. They state that this Reliability
Standard should be clarified and recommend specific revisions to
Requirements R1.6, R2.1, R2.2 and Levels of Non-Compliance.
1779. Northern Indiana expresses concern about the statement in P
1062 of the NOPR that ``load models used in system studies have a
significant impact on system performance * * *.'' Northern Indiana
believes the opposite is true, i.e., system performance has a
significant impact on load models. The goal of the models is to attempt
to capture system performance.
1780. MidAmerican supports the proposed clarifications to operating
steps and to footnote (b). International Transmission states that more
clarification should be provided for the thresholds of normal and
emergency ratings. There are potential inconsistencies with respect to
whether or not an entity can plan to operate above normal ratings, but
below emergency ratings, and for how long.
1781. Northern Indiana also takes issue with the NOPR proposal that
no load or transactions be interrupted except for consequential load
loss. Attempting to reduce the probability of load loss to zero would
greatly increase capital spending, and therefore increase rates to
customers, and all in the name of achieving an unattainable goal. PG&E
disputes that the Reliability Standard should provide limits on the
magnitude and duration of consequential load loss. Determining the
magnitude and consequences of load loss is a factor in the economic
evaluation during the development of transmission expansion plans. This
economic evaluation is not an appropriate subject for this Reliability
Standard. Northern Indiana urges the Commission to acknowledge that
planning studies by nature must balance infrastructure improvement and
expansion against site-specific and regional load projections, using
available resources. It questions whether the NOPR reflects a proper
balance between the many costs involved and the benefits, if any, that
would be realized.
1782. Entergy opposes the Commission's proposed guidance concerning
footnote (b) to Table 1 for two reasons. First, Entergy believes the
Commission should give due weight to the technical expertise of NERC
and permit NERC to address these matters through Reliability Standards
development process. Second, the Commission's guidance suggests that it
views all transmission outages as having the same level of importance
to and impact on the interconnected transmission grid. Entergy states
that the Commission should recognize that the effect of transmission
outages can be local in nature and have no impact on the reliability of
the Bulk Power System. Removing the transmission operator's ability to
shed load or enact other system adjustments as appropriate for a single
contingency would result in significant facility upgrade costs simply
to avoid the consequence of a local outage. Entergy requests that the
Commission clarify that its guidance does not constrain the
transmission operator's ability to determine the best course of action
to take to address any reliability constraint that may result from
these local outages.
1783. PG&E disagrees with the Commission's proposal to delete from
footnote (b) of this Reliability Standard the phrase ``to prepare for
the next contingency, system adjustments are permitted, including
curtailments of contracted Firm (non-recallable reserved) electric
power transfers.'' \455\ PG&E states that this phrase permits critical
system adjustments to reduce the potential for and impact of future
contingencies. It would allow re-scheduling power (but not load
shedding) as part of manual system adjustment after the first Category
B contingency (first N-1) to bring the system back to a safe operating
point before the next Category B contingency (second N-1). This phrase
is consistent with the manual system adjustment allowed in Category
C.3.\456\ PG&E states that, contrary to the Commission's
interpretation, footnote (c) does not capture this phrase. The
difference between footnote (b) as part of Category B and Category C.3
is that footnote (b) applies before the second N-1, whereas Category
C.3 applies after the second N-1. Without this phrase in footnote (b),
no manual system adjustment would be
[[Page 16582]]
allowed after a Category B contingency, which would be inconsistent
with Category C.3.
---------------------------------------------------------------------------
\455\ Id. at P 1084.
\456\ From TPL Standards Table 1, Category C.3 is Category B
(B1, B2, B3 or B4) contingency, manual system adjustments, followed
by another Category B (B1, B2, B3 or B4) contingency.
---------------------------------------------------------------------------
1784. APPA and LPPC recommend that changes to the footnotes of
Table 1 be subject to the NERC Reliability Standards development
process. They state that the footnotes have been extensively reviewed
by technical experts at NERC for several years and currently represent
a general consensus among these industry technical experts. Changes to
the footnotes affect Table 1 and have a direct impact on the
determination of the severity of consequences that were approved along
with the original standard. APPA also states that consideration of
reliability impacts of spare equipment strategies and obligations of
all generators to have the same voltage ride through capabilities are
important changes that should not be made by Commission fiat.
ii. Commission Determination
1785. The Commission approves TPL-002-0 as a mandatory and
enforceable Reliability Standard. In addition, we direct the ERO to
develop modifications to TPL-002-0 through the Reliability Standards
development process, as discussed below.
1786. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, R1.3.2 of TPL-002-0 requires an entity assessing system
performance to cover ``critical system conditions and study years'' as
deemed appropriate by the entity performing the study, but it does not
specify the rationale for determining critical system conditions and
study years. The Commission directs the ERO to modify TPL-002-0 to
require that critical system conditions and study years be determined
in the same manner as it directed with regard to TPL-001-0. The
Commission's explanation of the need for that change applies equally
here.
1787. With regard to Northern Indiana's concerns, we disagree that
the proposal to address situations in which critical equipment may be
unavailable for a prolonged period requires planned and forced outage
schedules for the next ten years. Reliability Standard TPL-002-0
requires consideration of planned outages at those demand levels for
which planned outages are performed but does not address situations in
which critical long lead time equipment, such as a transformer or phase
angle regulator, may be unavailable for a prolonged period that could
extend into periods where planned outages of such equipment would not
normally be performed. Assessments of these situations do not require
outage schedules for the next ten years but rather identification of
which facilities are deemed to be critical that have long lead times
for repair or replacement. Given that planned outage considerations of
such long lead time equipment are inexorably linked to spare equipment
strategy, consistent with our discussion of the issue above in
connection with spare equipment strategy, the Commission directs the
ERO to modify the Reliability Standard to require assessments of
planned outages of long lead time critical equipment consistent with
the entity's spare equipment strategy.
1788. In the NOPR, the Commission identified an implicit assumption
in the TPL Reliability Standards that all generators are required to
ride through the same types of voltage disturbances and remain in
service after the fault is cleared. This implicit assumption should be
made explicit. Commenters agree with the proposed requirement for all
generators to ride through the same set of Category B and C events as
required for wind generators. The Commission understands that NRC has
both degraded voltage and loss of voltage requirements. The degraded
voltage requirement allows the voltage at the auxiliary power system
busses to go below the minimum value for a time frame that is usually
much longer than normal fault clearing time.\457\ If a specific nuclear
power plant has an NRC requirement that would force it to trip off-line
if its auxiliary power system voltage was depressed below some minimum
voltage, the simulation should include the tripping of the plant in
addition to the faulted facilities. In this regard, the Commission
agrees that NRC requirements should be used when implementing the
Reliability Standards. Using NRC requirements as input will assure that
there is consistency between the Reliability Standards and the NRC
requirement that the system is accurately modeled. Accordingly, the
Commission directs the ERO to modify the Reliability Standard to
explicitly require either that all generators are capable of riding
through the same set of Category B and C contingencies, as required by
wind generators in Order No. 661, or that those generators that cannot
ride through be simulated as tripping. If a generator trips due to low
voltage from a single contingency, the initial trip of the faulted
element and the resulting trip of the generator would be governed by
Category B contingencies and performance criteria.
---------------------------------------------------------------------------
\457\ 10 CFR 50, Appendix a, GDC17.
---------------------------------------------------------------------------
1789. The Commission agrees with NRC that for operations purposes
the N-1 condition is always analyzed from the conditions being
experienced. In other words, allowing for the 30 minute system
adjustment period, the system must be capable of withstanding an N-1
contingency, with load shedding available to system operators as a
measure of last resort to prevent cascading failures. However, for
planning purposes, a different analysis applies. The N-1 condition is a
Category B event under TPL-002-0, and, following the N-1 contingency,
the system must be stable and thermal loading and voltages be within
applicable limits. Some adjustment of generation or other controls is
permitted to return loadings to within continuous ratings, provided the
loadings before adjustments are within the emergency or short-term
ratings. Under TPL-002-0 the system is not required to be able to
withstand another N-1 contingency. That N-1 requirement is a Category C
contingency which is addressed by TPL-003-0. The Commission has
addressed NRC's comment concerning N-1 contingencies in real-time
operation in TOP-002. In regard to the specific revisions proposed by
NRC, the Commission directs the ERO to consider these as part of the
Reliability Standards development process.
1790. In regard to Northern Indiana's comment concerning the load
modeling statement made in the NOPR, it should be clear that the
context of the discussion is system performance during simulations.
Load models used in simulations clearly should, to the extent feasible,
represent the actual performance of the aggregate mix of industrial,
commercial and residential loads. If the load model representations
used in simulations do not mirror the actual performance of loads,
especially during dynamic simulations, but also when carrying out
voltage stability studies, the simulation results will not be accurate.
Because load representation in simulations has a significant impact on
simulation results and often load models are not well known, it is
common practice for planners to perform sensitivity studies with a
range of load models. Accordingly, as proposed in the NOPR, the
Commission directs the ERO to modify the Reliability Standard to
require documentation of load models used in system studies and the
supporting rationale for their use.
1791. In the NOPR, the Commission set forth its rationale for
proposing that the ERO clarify the phrase ``permit operating steps
necessary to maintain system control'' in footnote (a) to Table 1.\458\
Specifically, the Commission stated that the operating steps required
[[Page 16583]]
to relieve emergency loadings and return the system to a normal state
should not include firm load shedding. MidAmerican agrees with the
Commission. International Transmission states clarification is required
on the thresholds for normal and emergency ratings and, in particular,
on whether an entity can plan to operate above normal ratings but below
emergency ratings and for how long. The Commission agrees that this
issue requires clarification and therefore directs the ERO to modify
the standard to clarify the phrase of footnote (a) that states ``permit
operating steps necessary to maintain system control'' to clarify the
use of emergency ratings.
---------------------------------------------------------------------------
\458\ NOPR at P 1083.
---------------------------------------------------------------------------
1792. The Commission stated in the NOPR that footnote (b) raises
three issues that need to be addressed.\459\ Two relate to the use of
planned or controlled load interruption under certain circumstances,
and the third relates to the use of system adjustments including
curtailment of firm transfers to prepare for the next contingency.
Northern Indiana and Entergy disagree with the Commission's proposal to
modify footnote (b) to state that load shedding for a single
contingency is not permitted except in very special circumstances where
such interruption is limited to the firm load associated with the
failure (consequential load loss). The commenters argue that the impact
of transmission outages can be local in nature and have no impact on
the reliability of the Bulk-Power System and that removing the option
to shed load in a local area for a single contingency would result in
significant facility upgrade costs and therefore increased rates to
customers simply to avoid a local outage. Entergy seeks clarification
that the Commission does not intend to constrain the transmission
operator's ability to determine the best course of action to address
local reliability constraints.
---------------------------------------------------------------------------
\459\ Id. at P 1084.
---------------------------------------------------------------------------
1793. The NOPR proposed a modification that would clarify footnote
(b) as disallowing loss of such firm load or the curtailment of firm
transactions after a first contingency of the bulk electric system. In
its comments to the Staff Preliminary Assessment, NERC agreed with this
interpretation, representing that a practice that permits the planned
interruption of ``firm transmission service'' is a misapplication of
the Reliability Standard.\460\ Some commenters now argue otherwise, and
in some cases cite examples where, based on a balance of economic and
reliability considerations, it may be preferable to plan the bulk
electric system in such a manner that contemplates the interruption of
some firm load customers in the event of a N-1 contingency. We view
these arguments as based largely on the matter of economics, not
reliability, with the underlying premise that it is not economically
feasible to invest in the bulk electric system to the point that it can
continue service to all firm load customers under some specific N-1
scenarios. Therefore, they argue, the ambiguities of footnote (b)
should be interpreted to allow that an entity plan for some amount of
load loss to avoid costly infrastructure investments.
---------------------------------------------------------------------------
\460\ ``NERC standards, including footnote (b), are not intended
to endorse or approve planning the interconnection using radial
configurations as a preferred method for reliably serving load, nor
do NERC standards consider load shedding acceptable for a single
contingency.'' NERC comments to the Staff Preliminary Assessment at
57-58.
---------------------------------------------------------------------------
1794. The Commission considers this matter to be a fundamental
issue of transmission service. Indeed, the ERO's definition of ``firm
transmission service'' specifically states that it is the ``highest
quality (priority) service offered to customers under a filed rate
schedule that anticipates no planned interruption.''
1795. Based on the record before us, we believe that the
transmission planning Reliability Standard should not allow an entity
to plan for the loss of non-consequential load in the event of a single
contingency.\461\ The Commission directs the ERO to clarify the
Reliability Standard. Regarding the comments of Entergy and Northern
Indiana that the Reliability Standard should allow entities to plan for
the loss of firm service for a single contingency, the Commission finds
that their comments may be considered through the Reliability Standards
development process. However, we strongly discourage an approach that
reflects the lowest common denominator.\462\ The Commission also
clarifies that an entity may seek a regional difference to the
Reliability Standard from the ERO for case-specific circumstances.
---------------------------------------------------------------------------
\461\ Consequential load is the load that is directly served by
the elements that are removed from service as a result of the
contingency.
\462\ See Order No. 672 at P 329.
---------------------------------------------------------------------------
1796. PG&E disputes that the Reliability Standard should provide
limits on the magnitude and duration of consequential load loss, as
this is an economic evaluation and is not an appropriate goal for this
Reliability Standard. The Commission disagrees. Indeed in its comments
to the Staff Preliminary Assessment, the ERO raised the issue of what
is an acceptable magnitude and duration of consequential load
loss.\463\ The Commission notes that most utilities have guidelines for
the magnitude and duration of load loss that is acceptable on radial
facilities before the facilities are looped to provide a second source
of supply to accommodate load growth. NERC also stated that it
recognizes that looped configurations are key to the reliable operation
of the Interconnection and to meet reasonable expectations for reliable
service to loads.\464\ The Commission, therefore, suggests that the ERO
consider developing a ceiling on the amount and duration of
consequential load loss that will be acceptable. If the ERO determines
that such a ceiling is appropriate, it should be developed through the
ERO's Reliability Standards development process. Further, we note that
the DOE thresholds for reporting disturbances on Form EIA-417 would be
one example of an appropriate starting point for developing such a
ceiling. These thresholds for load loss are 300 MW for 15 minutes or
50,000 customers for one hour, whichever is greater.
---------------------------------------------------------------------------
\463\ NERC Comments to Staff Preliminary Assessment at 56-57.
\464\ ``NERC recognizes that looped configurations are key to
the reliable operation of the interconnection, and to meet
reasonable expectations for reliable service to loads.'' Id. at 57.
---------------------------------------------------------------------------
1797. The third issue with footnote (b) relates to the Commission's
proposal in the NOPR to delete the footnote's second sentence, which
states ``[t]o prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power transfers.'' \465\ PG&E disagrees with the
Commission's proposal because it allows re-scheduling power (but not
load shedding) as part of manual adjustment after the first Category B
contingency to bring the system back to a safe operating point. The
Commission agrees that footnote (b) should permit manual adjustments
including generation redispatch and transmission reconfiguration, but
not load shedding, to return the system to a normal operating state
within the time period permitted by the emergency or short term
ratings. The Commission understands that this is the normal practice
used by most transmission planners. However, the system adjustments
permitted in the statement above includes curtailments of contracted
firm, non-recallable reserved and electric power transfers and this is
not acceptable for Category B single contingencies. Therefore, the ERO
should modify the sentence to indicate that manual system adjustments,
except
[[Page 16584]]
for shedding firm load or curtailment of firm transfers, are permitted
after the first contingency to bring the system back to a normal
operating state. The Commission disagrees with PG&E's statement that
the difference between footnote (b) as part of Category B and Category
C.3 is that footnote (b) applies before the second N-1 contingency,
whereas Category C.3 applies after the second N-1 contingency. Rather,
manual adjustments referred to in both cases apply after the first N-1
contingency. The Commission, therefore, directs the ERO to modify the
second sentence of footnote (b) to clarify that manual system
adjustments other than shedding of firm load or curtailment of firm
transfers are permitted to return the system to a normal operating
state after the first contingency, provided these adjustment can be
accomplished within the time period allowed by the short term or
emergency ratings.
---------------------------------------------------------------------------
\465\ NOPR at P 1083.
---------------------------------------------------------------------------
1798. Accordingly, the Commission approves Reliability Standard
TPL-002-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-002-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions be determined in the same manner as we
propose to require for TPL-001-0; (2) requires assessments of planned
outages of long lead time critical equipment consistent with the
entity's spare equipment strategy; (3) requires all generators to ride
through the same set of Category B and C contingencies as required by
wind generators in Order No. 661, or to simulate those generators that
cannot ride through as tripping; (4) requires documentation of load
models used in system studies and supporting rationale for their use;
(5) clarifies the phrase ``permit operating steps necessary to maintain
system control'' in footnote (a) and the use of emergency ratings and
(6) clarifies footnote (b) in regard to load loss following a single
contingency, specifying the amount and duration of consequential load
loss and system adjustments permitted after the first contingency to
return the system to a normal operating state, as discussed above.
d. System Performance Following Loss of Two or More Elements (TPL-003-
0)
1799. Reliability Standard TPL-003-0 seeks to ensure that the
future Bulk-Power System is planned to meet the system performance
requirements of a system with the loss of multiple elements. It does
this by requiring that the transmission planner and the planning
authority annually evaluate and document the ability of its
transmission system to meet the performance requirements of Category C
contingencies specified in Table 1 (i.e., events resulting in the loss
of two or more elements) for both the near-term and the longer-term
planning horizons. TPL-003-0 requires the preparation of a documented
plan to achieve the necessary performance requirements if the system is
unable to meet the Category C performance criteria.
1800. TPL-003-0 applies to each planning authority and transmission
planner. They must demonstrate annually through valid assessments that
their portion of the interconnected transmission system is planned to
meet the performance requirements of Category C with all transmission
facilities in service over a planning horizon that takes into account
lead times for corrective plans. The Reliability Standard also requires
the applicable entities to consider planned outages of transmission
equipment for those demand levels for which they perform such outages.
The Reliability Standard defines various categories of conditions to be
simulated. The specific study elements selected from each of the
categories for assessments, including the subset of Category C
contingencies to be evaluated, require approval by the associated
regional reliability organization.
1801. The Commission proposed in the NOPR to approve Reliability
Standard TPL-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,
we proposed to direct NERC to submit a modification to TPL-003-0 that:
(1) Requires that critical system conditions be determined by
conducting sensitivity studies (as elaborated in our discussion of TPL-
001-0); (2) makes certain clarifications to footnote (c) to Table 1;
(3) requires the applicable entities to define and document the proxies
necessary to simulate cascading outages and (4) tailors the purpose
statement to reflect the specific goal of the Reliability Standard.
1802. The Commission also sought comments on one potential addition
to TPL-003-0. It noted that Category C3 of this Reliability Standard
involves a situation in which two single contingencies occur, with
manual system adjustments permitted after the first contingency to
prepare for the next one (generally referred to as N-1-1). However, the
Commission also noted that should the second contingency occur before
the manual system adjustments can be completed, the local area and
potentially the system would be exposed to risk of cascading outages.
For that reason some entities plan and operate their systems so that
they are able to withstand the simultaneous occurrence of the two
contingencies (normally referred to as N-2) for major load pockets. The
Commission sought comments on the value and appropriateness of
including such a requirement in TPL-003-0.
i. Comments
1803. LPPC recommends that changes to footnotes of Table 1 be
subject to the NERC Reliability Standards development process. It
states that the footnotes have been extensively reviewed by technical
experts at NERC for several years and currently represent a general
consensus among these industry technical experts which should be given
due weight by the Commission. Changes to the footnotes impact Table 1
and have a direct impact on the determination of the severity of
consequences that were approved along with the original Reliability
Standard.
1804. FirstEnergy supports the proposed requirement to document
proxies of subsequent line trips due to thermal overload and low
voltage generation trips to evaluate potential cascading conditions.
FirstEnergy states it currently is required to account for these items
in its planning process.
1805. EEI questions the value of providing proxies when planners
conduct thousands of studies based on combinations of contingencies
under a broad range of circumstances and conditions, especially in
longer-term planning horizons where the uncertainty around the value of
any one variable is already very high. SoCal Edison states that one can
determine the cascading outages in load flow studies. In transient
stability studies, if the outage is severe, then the thermal overload
relays and undervoltage relays, if modeled, will trip the load. If the
load tripped was not planned to be tripped for this outage, then the
planning authority should take the necessary steps to avoid this
situation, as cascading is not allowed.
1806. LPPC and Northern Indiana oppose the proposal to require
proxies necessary to simulate cascading outages be defined and
documented. Northern Indiana states that there is no consensus on what
these proxies should be. LPPC states that utility planners have
traditionally used their engineering judgment to simulate a
conservative estimate of the level of thermal overload or low voltage
that will cause the likelihood of subsequent line or generator trips
and cascading events. LPPC states that this approach has been
[[Page 16585]]
successful, and NERC should not be asked to second-guess the decisions
of operators in this area. That could result in the adoption of less
conservative, least common denominator, design assumptions across all
regions and reduce modeling flexibility and use of engineering
judgment. Proxies are typically tailored to specific systems because
the development of proxies is highly dependent on regional differences
and localized knowledge. If the Commission determines that independent
review of utility outage simulation proxies is necessary, Regional
Entities should conduct that review, because they better understand the
regional and localized factors that influence the proxies.
1807. EEI requests that the Commission clarify the meaning of the
term ``controlled load interruption'' and the meaning of its statement
that ``to avoid undue negative impact on competition, third party
studies could be permitted to implement the same or less controlled
load interruption as used by the transmission owner.'' \466\
---------------------------------------------------------------------------
\466\ Id. at P 1097.
---------------------------------------------------------------------------
1808. NRC states that this Reliability Standard should be clarified
in regard to the N-1-1 condition. In addition, it recommends specific
changes to Requirements R1.6, R.1.2 and R2.2.
1809. A number of commenters respond to the Commission's request
for comments on the value and appropriateness of including the ability
of the system to withstand two simultaneous contingencies for major
load pockets. NERC states that this issue has been recognized as
needing clarification, and it welcomes comments in the development of
these revisions in accordance with its Reliability Standards
development process. NERC states that it is developing a proposal for a
transmission availability data system that will provide a quantitative
(probabilistic) basis for judging the likelihood of various multi-
element contingencies which will be helpful in determining the value of
this proposal.
1810. APPA, LPPC and National Grid state that imposing N-2 planning
may be difficult to administer since there is no consensus on what
constitutes a ``major load pocket.'' LPPC states that the definition of
major load pockets has been, and is still being debated. As there is no
nation-wide consensus on the term's definition, no list of major load
pockets exists. Because load pockets and their boundaries change with
the dynamically changing system and load patterns, it is difficult to
establish or administer a rule that encompasses the particular sub-
region to which such an N-2 requirement would apply.
1811. APPA and EEI believe such provisions would significantly
expand planning requirements for extremely unlikely events that in most
cases are not cost effective to build into system planning decisions.
They explain that the Reliability Standard currently includes the more
likely situation, i.e., where two events occur in a time frame that
allows some time to adjust in response to the first event. APPA and EEI
state that various planning entities may, of course, study much more
extreme events, including the hypothetical the Commission poses,
especially if formal state or regional planning requires such studies,
and actual preparation for extreme events is viewed as cost-effective
in a particular area. However, this level of planning sensitivity is
simply unnecessary for many regions of the country. They ask that if
the Commission envisions changes to provide for N-2 service to load
pockets, a dialogue must first be initiated within the industry and
with state public utility commissions to identify such load pockets,
target the required transmission investments (which could be very
substantial) and develop plans for allocating the costs of such
investments.
1812. FirstEnergy comments that, although simultaneous C.3
independent contingencies may pose potentially high risk, they are most
likely extremely low in probability. FirstEnergy states that it
nevertheless routinely evaluates these contingencies across its system
for facilities 200 kV and higher and suggests that if this analysis is
made a requirement, it should be limited to an extra high voltage
subset of the Bulk-Power System.
1813. MISO believes that evaluation of multiple contingency events
should only reside in the planning arena and not in the operations
environment. It states that the current Reliability Standard provides a
reasonable and time tested methodology.
1814. National Grid opposes applying this N-2 criterion across the
board. It states that N-2 planning is usually relied upon when a
particular area does not have the resources or flexibility to adopt the
N-1-1 approach. The Bulk-Power System is designed differently in every
region, and there is no need to impose N-2 planning where regions are
satisfactorily implementing the N-1-1 methodology.
1815. SDG&E states that the N-2 consideration for major load
pockets is neither of value nor appropriate for transmission planning
entities at large. The probability of such a contingency for a major
load pocket is very low, and the costs for addressing such a remote
contingency would be significant. SoCal Edison states the potential
number of multi-contingency events that could be studied under TPL-003-
0 is staggering. Planners should be given flexibility to select
generation and transmission elements that reflect a broad range of
potential combinations without having to commit resources to conduct
potentially hundreds or thousands of contingency studies. Northern
Indiana contends that this requirement is in effect a third back-up
capability, that it would be prohibitive in terms of time and cost, and
that it would take many years to put the infrastructure it would
require into place.
1816. PG&E believes there is no need for a general requirement to
withstand the simultaneous occurrence of any two contingencies for
major load pockets. It states that IRO-005 provides for contingencies
that are credible when operating below IROL in current day operations.
The TPL group of Reliability Standards already require provisions for
specific circumstances based on evaluations that take into account the
probability of an outage occurring and the associated consequences when
transmission plans are developed. PG&E states that TPL-003-0, Category
C.5 contingency already addresses the more probable simultaneous
outages (due to common-mode failure) that could occur. PG&E maintains
that simultaneous occurrence of other contingencies is not credible.
The principles incorporated in the Reliability Standards require that
evaluations of credibility be balanced against potential impact, and
investing resources to prevent improbable events diverts attention and
focus from more critical Reliability Standards and more probable
conditions.
ii. Commission Determination
1817. The Commission approves proposed Reliability Standard TPL-
003-0 as a mandatory and enforceable Reliability Standard. In addition,
we direct the ERO to develop modifications to TPL-003-0 through the
Reliability Standards development process, as discussed below.
1818. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, Requirement R1.3.2 of TPL-003-0 requires an entity assessing
system performance to cover ``critical system conditions and study
years'' as deemed appropriate by the entity performing the study, but
that the Requirement does not specify the rationale for determining
critical system conditions and study years. The Commission directs the
ERO to modify TPL-003-0 to require that
[[Page 16586]]
critical system conditions and study years be determined in the same
manner as we directed with regard to TPL-001-0, for the reasons as set
forth in our discussion of TPL-001-0.
1819. The intent underlying the statement that ``to avoid undue
negative impact on competition, third party studies should be permitted
to implement the same or less controlled load interruption as used by
the transmission owner'' is to ensure that third parties have access to
the same options that the transmission owner uses to alleviate
reliability constraints including those related to controlled load
shedding. For example, if a transmission owner designs its system to
result in a controlled load shedding of 300 MW for Category C
contingencies, designs proposed for third parties requesting
interconnections to that system must also be permitted, but not
required, to have 300 MW of controlled load shedding for the same
Category C contingencies. The Commission directs the ERO to modify
footnote (c) of Table 1 to the Reliability Standard to clarify the term
``controlled load interruption.'' In response to LPPC's comments on
modification procedures, the Commission agrees that changes to the
footnotes of Table 1 should be addressed through the ERO's Reliability
Standards development process.
1820. The Commission stated in the NOPR that the concern involved
relates to the use of thermal overloads or low voltage proxies to judge
the likelihood of subsequent line or generator trips leading to a
cascading outage.\467\ The Commission agrees with SoCal Edison that, if
an entity models overload relays, undervoltage relays, all remedial
action schemes including those of neighboring systems and has a good
load representation, then proxies are not required. However, due to
modeling and simulation limitations this is often not the case and
planners invariably use proxies.\468\ Recognizing this and the range of
proxies currently in use, the Transmission Issues Subcommittee of the
NERC Planning Committee recommended that proxies used in simulations be
defined until such time as improved analytical tools and models are
available to simulate cascading events.
---------------------------------------------------------------------------
\467\ Id. at P 1098.
\468\ See WECC Disturbance Performance Table W-1 and Figure W-1
of Allowable Effects on other Systems, NERC/WECC Planning Standards
April 10, 2003.
---------------------------------------------------------------------------
1821. The Commission disagrees with LPPC that defining and
documenting proxies will result in the adoption of less conservative,
least common denominator design assumptions across all regions and
reduce modeling flexibility and engineering judgment. To the contrary,
the Commission believes that such sharing of information will improve
knowledge and understanding and promote a more rigorous approach to
analyzing cascading outages. The Commission agrees with LPPC that it
may be preferable for the Regional Entities to conduct the review of
proxies, because they better understand the regional and localized
factors that influence the proxies. However, we expect the ERO to
coordinate between regions to assure that best practices are shared
among the Regional Entities. Accordingly, the Commission directs the
ERO to modify the Reliability Standard to require definition and
documentation of proxies necessary to simulate cascading outages.
1822. No comments were received on the Commission's proposal that
the purpose statement of TPL-003-0 be tailored to reflect the specific
goal of the Reliability Standard. The Commission directs that this
modification be made. Reliability Standards should be clear and
unambiguous, and a clear statement of a Reliability Standard's purpose
and goal is one of the features necessary to achieve this end.
1823. The NRC's comments on TPL-003-0 parallel its comments on TPL-
002-0. The Commission discussed those comments above, and its
conclusions there apply equally here. The Commission, for the same
reasons set forth in our discussion of TPL-002-0, directs the ERO to
address NRC concerns through its Reliability Standards development
process.
1824. The Commission received numerous comments on its request for
comments on the appropriateness and value of including the ability of
the system to withstand two simultaneous Category B contingencies for
major load pockets. The Commission stated that it was aware that
several entities currently apply this approach and notes that one
entity was actually commended by NERC for doing so as part of its
readiness review. FirstEnergy states that it routinely evaluates these
contingencies across its system for 200 kV and higher. NERC states that
this issue has been recognized as requiring clarification, and it
welcomes comments on these revisions in accordance with the Reliability
Standards development process.
1825. Many commenters state that, without a consensus on what
constitutes a major load pocket, little progress can be made in this
regard. LPPC states that the definition of major load pockets has been
and is still being debated. National Grid states that N-2 planning is
usually relied upon when a particular area does not have the resources
and flexibility to adopt the N-1-1 approach. The Commission agrees with
National Grid but notes that this is more applicable to the operating
domain, something that MISO opposes. PG&E states that this approach is
not necessary because Category C5 already addresses more probable
simultaneous outages due to common mode failure. The Commission
disagrees since Category C5 only deals with a loss of any two circuits
on a multi-circuit tower line and not a simultaneous loss of a line and
a generator which was envisaged by the request for comments. Many
commenters indicated that this was a very low probability event and the
costs for addressing such an event would be significant. As a result,
EEI states that a dialogue must first be initiated within the industry
and with state public utility commissions to identify such load
pockets, to target the required potentially significant transmission
investments and to develop plans for allocating the costs of such
investments. In light of these comments, the Commission does not intend
to recommend action on this issue at this time and, instead, directs
the ERO to consider the comments in possible future revisions to the
Reliability Standard.
1826. Accordingly, the Commission approves Reliability Standard
TPL-003-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-003-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions be determined in the same manner as we
propose to require for TPL-001-0; (2) modifies footnote (c) to Table 1
to clarify the term ``controlled load interruption;'' (3) requires
applicable entities to define and document the proxies necessary to
simulate cascading outages and (4) tailors the purpose statement to
reflect the specific goal of the Reliability Standard.
e. System Performance Following Extreme Events (TPL-004-0)
1827. The goal of Reliability Standard TPL-004-0 is to ensure that
the future Bulk-Power System is evaluated to assess the risks and
consequences of an extreme event involving the loss of multiple
elements. It seeks to do this by requiring the transmission planner and
the planning authority to evaluate and document annually the risks and
consequences of Category D contingencies (i.e., extreme events
[[Page 16587]]
resulting in loss of two or more elements or cascading) for the near-
term (five-year) planning horizon.
1828. TPL-004-0 applies to each planning authority and transmission
planner. Each must demonstrate annually through valid assessments that
its portion of the interconnected transmission system is evaluated for
the risks and consequences of a number of each of the extreme
contingencies of Category D with all transmission facilities in service
over a planning horizon that takes into account lead times for
corrective plans. TPL-004-0 also requires that planned outages of
transmission equipment be considered for those demand levels for which
planned outages are performed. It defines various categories of
conditions to be simulated. The associated regional reliability
organization must approve the specific study elements selected from
each of the categories for assessment, including the subset of Category
D contingencies to be evaluated.
1829. The Commission proposed in the NOPR to approve Reliability
Standard TPL-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,
we proposed to direct NERC to submit a modification to TPL-004-0 that:
(1) Requires that critical system conditions be determined in the same
manner as proposed for TPL-001-0; (2) requires the identification of
options for reducing the probability or impacts of extreme events that
cause cascading; (3) requires that, in determining the range of extreme
events to be assessed, the contingency list of Category D be expanded
to include recent events and (4) tailors the purpose statement to
reflect the specific goal of the Reliability Standard.
i. Comments
1830. MidAmerican supports the Commission's proposed modifications
to the Reliability Standard as reasonable and agrees with the
Commission that the Reliability Standard should not require
improvements for low probability events that cannot be justified.\469\
MidAmerican supports developing options for any events listed in TPL-
004-0 that result in cascading outages and suggests use of
probabilistic estimates to determine which, if any, of the TPL-004
extreme events options should be estimated to reduce their probability
or impacts.
---------------------------------------------------------------------------
\469\ See NOPR at P 1112.
---------------------------------------------------------------------------
1831. FirstEnergy, EEI, APPA, TVA and Northern Indiana all oppose
the expansion of the list of extreme contingencies to include natural
disasters such as hurricanes and ice storms. They state that the
potential contingencies resulting from this expansion are endless and
therefore impractical to consider through engineering studies. As a
result, additional requirements in this Reliability Standard are
unnecessary. EEI and APPA state that to the extent that such events
will happen, entities historically have put heavy emphasis on emergency
planning and procedures, which are addressed by the EOP group of
Reliability Standards.
ii. Commission Determination
1832. The Commission approves proposed Reliability Standard TPL-
004-0 as mandatory and enforceable. In addition, we direct the ERO to
develop modifications to TPL-004-0 through the Reliability Standards
development process, as discussed below.
1833. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, Requirement R1.3.2 of TPL-004-0 requires an entity assessing
system performance to cover ``critical system conditions and study
years'' as deemed appropriate by the entity performing the study, but
it does not specify the rationale for determining critical system
conditions and study years. The Commission directs the ERO to modify
TPL-004-0 to require that critical system conditions and study years be
determined in the same manner as we directed with regard to TPL-001-0
and for the reasons stated there.
1834. MidAmerican states that it supports the proposal to modify
TPL-004-0 to require identification of options for reducing the
probability or impacts of extreme events that cause cascading.
Accordingly, for the reasons cited in the NOPR, the Commission directs
the ERO to modify the Reliability Standard to make this modification to
the Reliability Standard.
1835. All commenters that responded on the issue opposed the
Commission's proposal to modify TPL-004-0 to require that, in
determining the range of the extreme events to be assessed, the
contingency list of Category D be expanded to include recent events
such as hurricanes and ice storms. The Commission is not persuaded by
the commenters' contention that expansion of the extreme events list
will lead to an endless list of possibilities. The two that the
Commission used are examples from the general news media. While the
NOPR referred to two recent events, other examples include: (1) Loss of
a large gas pipeline into a region or multiple regions that have
significant gas-fired generation; (2) a successful cyber attack; (3)
regulation that restricts or eliminates the use of a river or lake or
other body of water as the cooling source for generation; (4) shutdown
of a nuclear power plant and other facilities a day or more prior to a
hurricane, tornado or wildfire, or other event and (5) the loss of
older transmission lines, which may not be constructed to meet an
entity's present radial ice loading requirements, while the newer or
stronger transmission lines remain in service. The above examples are
not an exhaustive list, however, the Commission would not expect the
range of scenarios to be much more extensive than this, either. Thus,
we are not expecting an endless list of scenarios and infinite number
of combinations in directing this modification. Each event is
identifiable for each entity based on its topology, facilities and
generation mix. Accordingly, the Commission directs the ERO to expand
the list of events with examples of such events identified above.
1836. The Commission received no comments on its proposal to modify
the purpose statement of TPL-004-0 to reflect the specific goal of the
Reliability Standard. The Commission directs that this modification be
made.
1837. Accordingly, the Commission approves Reliability Standard
TPL-004-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-004-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions be determined in the same manner as proposed
for TPL-001-0; (2) requires the identification of options for reducing
the probability or impacts of extreme events that cause cascading; (3)
requires that, in determining the range of extreme events to be
assessed, the contingency list of Category D be expanded to include
recent events and (4) tailors the purpose statement to reflect the
specific goal of the Reliability Standard.
f. Regional and Interregional Self-Assessment Reliability Reports (TPL-
005-0)
1838. Reliability Standard TPL-005-0 seeks to ensure that each
regional reliability organization conducts reliability assessments of
its existing and planned regional bulk electric system annually by
requiring it to assess and document the performance of its power system
for the current year, the next five years, and to analyze trends for
the longer-term planning horizons.
1839. The Commission proposed in the NOPR not to approve or remand
[[Page 16588]]
TPL-005-0, as it applies only to regional reliability organizations.
i. Comments
1840. EEI comments that TPL-005-0 should be revised to remove the
regional reliability organizations.
ii. Commission Determination
1841. Consistent with our discussion in the Common Issues section
above, we will not approve or remand TPL-005-0 until we receive
additional information from the ERO.
1842. In Order No. 890, the Commission stated that there will be a
series of technical conferences and regional meetings to obtain
industry input to achieving the goal of regional planning.\470\ The
Commission encourages the ERO to monitor those proceedings and use the
results as input to the Reliability Standards development process in
revising Reliability Standard TPL-005-0 to address regional planning
and related processes.
---------------------------------------------------------------------------
\470\ Order No. 890 at P 443.
---------------------------------------------------------------------------
g. Assessment Data From Regional Reliability Organizations (TPL-006-0)
1843. Reliability Standard TPL-006-0 seeks to ensure that the data
necessary to conduct reliability assessments is available by requiring
the regional reliability organization to provide NERC with Bulk-Power
System data, reports, demand and energy forecasts, and other
information necessary to assess reliability and compliance with NERC
Reliability Standards and relevant regional planning criteria.
1844. The Commission proposed in the NOPR not to approve or remand
TPL-006-0, as it applies only to regional reliability organizations.
i. Comments
1845. EEI agrees that TPL-006-0 should be revised to remove the
regional reliability organizations.
ii. Commission Determination
1846. Consistent with our discussion in the Common Issues section
above, the Commission will not approve or remand TPL-006-0.
13. VAR: Voltage and Reactive Control
1847. The Version 0 Voltage and Reactive Control (VAR) Reliability
Standard VAR-001-0 is intended to maintain Bulk-Power System facilities
within voltage and reactive power limits, thereby protecting
transmission, generation, distribution, and customer equipment and the
reliable operation of the Interconnection. The Voltage and Reactive
Control group of Reliability Standards is intended to replace the
existing VAR-001-0 and consists of two proposed Reliability Standards,
VAR-001-1 and VAR-002-1, with new Requirements. These two new proposed
Reliability Standards have been submitted by NERC as part of the August
28, 2006 Supplemental Filing for Commission review. NERC requested an
effective date of February 2, 2007 for VAR-001-1, and August 2, 2007
for VAR-002-1.
a. VAR-001-1 Voltage and Reactive Control
1848. Reliability Standard VAR-001-1 requires transmission
operators to implement formal policies for monitoring and controlling
voltage levels, acquire sufficient reactive resources, specify criteria
for generator voltage schedules, know the status of all transmission
reactive power resources, operate or direct the operation of devices
that regulate voltage and correct IROL or SOL violations resulting from
reactive resource deficiencies. VAR-001-1 also requires purchasing-
selling entities to arrange for reactive resources to satisfy their
reactive requirements.
1849. In the NOPR, the Commission proposed to approve VAR-001-1 as
mandatory and enforceable. In addition, the Commission proposed to
direct NERC to submit a modification to VAR-001-1 that: (1) Expands the
applicability to include reliability coordinators and LSEs; (2)
includes detailed and definitive requirements on ``established limits''
and ``sufficient reactive resources,'' and identifies acceptable
margins above the voltage instability points; (3) includes Requirements
to perform voltage stability assessments periodically during real-time
operations and (4) includes controllable load among the reactive
resources to satisfy reactive requirements. The Commission also
requested comments concerning NERC's assertion that all LSEs are also
purchasing-selling entities, and on the acceptable ranges of net power
factor range at the interface at which the LSEs receive service from
the Bulk-Power System during normal and extreme load conditions.
1850. Most comments address the specific modifications and concerns
raised by the Commission in the NOPR. Below, we address each topic
separately, followed by an overall conclusion and summary.
i. Applicability to Load-Serving Entities and Reliability Coordinators
(a) Comments
1851. EEI agrees with the Commission that the applicability of VAR-
001-1 should be expanded to include reliability coordinators and LSEs.
1852. MISO contends that the view and role of generator operators,
transmission operators and reliability coordinators are different, and
reliability coordinators' monitoring and response requirements are
addressed elsewhere in the Reliability Standards.
1853. In response to the Commission's request in the NOPR for
comments concerning whether all LSEs are also purchasing-selling
entities, SoCal Edison believes they are distinguishable. It states
that a purchasing-selling entity, according to the functional model,
makes financial deals across balancing authorities (from source to
sink). Within the area of a large balancing authority, such as the
CAISO, an LSE can serve load from a resource within the balancing
authority, so that there is no requirement to tag this transaction, and
technically there is no purchasing-selling entity involved.
1854. APPA is concerned that requiring VAR-001-1 to be applicable
to LSEs would require LSEs to conduct various studies and perform
reliability functions that have been assigned to other functional
entities. The role of LSEs in voltage stability assessments should be
limited to coordination and the provision of data. TAPS also questions
the need to expand applicability of these Reliability Standards to
LSEs. TAPS maintains that purchasing and selling utilities are already
subject to the Reliability Standards, and are required to satisfy any
reactive requirements through purchasing Ancillary Service No. 2 under
the OATT (or self-supply). TAPS believes that the addition of LSEs as
an additional applicable entity serves no reliability purpose.
(b) Commission Determination
1855. In a complex power grid such as the one that exists in North
America, reliable operations can only be ensured by coordinated efforts
from all operating entities in long-term planning, operational planning
and real-time operations. To that end, the Staff Preliminary Assessment
recommended and the NOPR proposed that the applicability of VAR-001-1
extend to reliability coordinators and LSEs.
1856. Since a reliability coordinator is the highest level of
authority overseeing the reliability of the Bulk-Power System, the
Commission believes that it is
[[Page 16589]]
important to include the reliability coordinator as an applicable
entity to assure that adequate voltage and reactive resources are being
maintained. As MISO points out, other Reliability Standards address
responsibilities of reliability coordinators, but we agree with EEI
that it is important to include reliability coordinators in VAR-001-1
as well. Reliability coordinators have responsibilities in the IRO and
TOP Reliability Standards, but not the specific responsibilities for
voltage levels and reactive resources addressed by VAR-001-1, which
have a great impact on system reliability. For example, voltage levels
and reactive resources are important factors to ensure that IROLs are
valid and operating voltages are within limits, and that reliability
coordinators should have responsibilities in VAR-001-1 to monitor that
sufficient reactive resources are available for reliable system
operations. Accordingly, the ERO should modify VAR-001-1 to include
reliability coordinators as applicable entities and include a new
requirement(s) that identifies the reliability coordinator's monitoring
responsibilities.
1857. The Commission agrees with SoCal Edison that not all LSEs are
purchasing-selling entities, because not all LSEs purchase or sell
power from outside of their balancing authority area. This
understanding is consistent with the NERC functional model and NERC
glossary. Both LSEs and purchasing-selling entities should have some
requirements to provide reactive power to appropriately compensate for
the demand they are meeting for their customers. Neither a purchasing-
selling entity nor a LSE should depend on the transmission operator to
supply reactive power for their loads during normal or emergency
conditions.
1858. VAR-001-1 recognizes that energy purchases of purchasing-
selling entities can increase reactive power consumption on the Bulk-
Power System and the purchasing-selling entities must supply what they
consume. The Commission agrees with APPA that LSEs would provide data
for voltage stability assessments. However, the Commission also
believes that LSEs have an active role in voltage and reactive control,
since LSEs are responsible for maintaining an agreed-to power factor at
the interface with the Bulk-Power System.
1859. While the Commission recognizes the point made by TAPS, that
purchasing-selling entities are required to satisfy any reactive
requirements through purchasing Ancillary Service 2 under the
OATT or self-supply, the Commission disagrees that adding LSEs to this
Reliability Standard serves no reliability purpose. As discussed in the
NOPR and the Staff Preliminary Assessment, LSEs are responsible for
significantly more load than purchasing-selling entities.\471\ The
reactive power requirements can have significant impact on the
reliability of the system and LSEs should be accountable for that
impact in the same ways that purchasing-selling entities are
accountable, by providing reactive resources, and also by providing
information to transmission operators to allow transmission operators
to accurately study the reactive power needs for both the LSEs' and
purchasing-selling entities' load characteristics.\472\ The Commission
recognizes that all transmission customers of public utilities are
required to purchase Ancillary Service No. 2 under the OATT or self-
supply, but the OATT does not require them to provide information to
transmission operators needed to accurately study reactive power needs.
The Commission directs the ERO to address the reactive power
requirements for LSEs on a comparable basis with purchasing-selling
entities.
ii. Acceptable Ranges of Net Power Factor Range
---------------------------------------------------------------------------
\471\ NOPR at P 1134.
\472\ Purchasing selling entities provide information concerning
their load through the INT series of Reliability Standards. Load
serving entities would need to provide similar information through
this Reliability Standard.
---------------------------------------------------------------------------
(a) Comments
1860. SoCal Edison states that its Bulk-Power System facilities are
designed and operated to provide a unity power factor during normal
load conditions, and that during extreme load conditions, this power
factor could be in the range of 0.95 to 1.0.
1861. APPA contends that it may be difficult to reach an agreement
on acceptable ranges of net power factors at the interfaces where LSEs
receive service from the Bulk-Power System because the acceptable range
of power factors at any particular point on the electrical system
varies based on many location-specific factors. APPA further states
that system power factors will be affected by the transmission
infrastructure used to supply the load. As an example, APPA states that
an overhead circuit may operate at a higher power factor than an
underground cable due to a substantial amount of reactive line
charging, and that a transmission circuit carrying low levels of real
power will tend to provide more reactive power, which will affect the
need to switch off capacitor banks at the delivery point to manage
delivery power factors.
(b) Commission Determination
1862. In the NOPR, the Commission asked for comments on acceptable
ranges of net power factor at the interface at which the LSEs receive
service from the Bulk-Power System during normal and extreme load
conditions. The Commission asked for these comments in response to
concerns that during high loads, if the power factor at the interface
between many LSEs and the Bulk-Power System is so low as to result in
low voltages at key busses on the Bulk-Power System, then there is risk
for voltage collapse. The Commission believes that Reliability Standard
VAR-001-1 is an appropriate place for the ERO to take steps to address
these concerns by setting out requirements for transmission owners and
LSEs to maintain an appropriate power factor range at their interface.
We direct the ERO to develop appropriate modifications to this
Reliability Standard to address the power factor range at the interface
between LSEs and the Bulk-Power System.
1863. We direct the ERO to include APPA's concern in the
Reliability Standards development process. We note that transmission
operators currently have access to data through their energy management
systems to determine a range of power factors at which load operates
during various conditions, and we suggest that the ERO use this type of
data as a starting point for developing this modification.
1864. The Commission expects that the appropriate power factor
range developed for the interface between the bulk electric system and
the LSE from VAR-001-1 would be used as an input to the transmission
and operations planning Reliability Standards. The range of power
factors developed in this Reliability Standard provides the input to
the range of power factors identified in the modifications to the TPL
Reliability Standards. In the NOPR, the Commission suggested that
sensitivity studies for the TPL Reliability Standards should consider
the range of load power factors.\473\
---------------------------------------------------------------------------
\473\ NOPR at P 1047.
---------------------------------------------------------------------------
iii. Requirements on ``established limits'' and ``sufficient reactive
resources''
(a) Comments
1865. Dynegy supports the Commission's proposal to include more
definitive requirements on ``established
[[Page 16590]]
limits'' and ``sufficient reactive resources.'' It recommends that VAR-
001-1 be further modified to require the transmission operator to have
more detailed and definitive requirements when setting the voltage
schedule and associated tolerance band that is to be maintained by the
generator operator. Dynegy states that the transmission operator should
not be allowed to arbitrarily set these values, but rather should be
required to have a technical basis for setting the required voltage
schedule and tolerance band that takes into account system needs and
any limitations of the specific generator. Dynegy believes that such a
requirement would eliminate the potential for undue discrimination, as
well as the possibility of imposing overly conservative and burdensome
voltage schedules and tolerance bands on generator operators that could
be detrimental to grid reliability, or conversely, the imposition of
too low a voltage schedule and too wide a tolerance band that could
also be detrimental to grid reliability.
1866. While MISO supports the concept of including more detailed
requirements, it believes that there needs to be a definitive reason
for establishing voltage schedules and tolerances, and that any
situations monitored in this Reliability Standard need to be limited to
core reliability requirements.
1867. EEI seeks clarification about whether the Commission is
suggesting that reactive requirements should aim for significantly
greater precision, especially in terms of planning for various
emergency conditions. If so, EEI cautions the Commission against ``
`putting too many eggs' '' in the reactive power `basket.' '' \474\ To
the extent compliance takes place pursuant to all other modeling and
planning assessments under the other Reliability Standards, EEI
strongly believes that the Commission should have some high level of
confidence that the system's reactive power needs can be met
satisfactorily across a broad range of contingencies that planners
might reasonably anticipate. Moreover, EEI believes that requirements
to successfully predict reactive power requirements in conditions of
near-system collapse would require significantly more creative
guesswork than solid analysis and contingency planning. For example,
EEI notes that the combinations and permutations of how a voltage
collapse could occur on a system as large as the eastern
Interconnection are numerous.
---------------------------------------------------------------------------
\474\ EEI at 99.
---------------------------------------------------------------------------
1868. EEI suggests that, alternatively, the Commission should
consider that reactive power evaluations should be conducted within a
process that is documented in detail and includes a range of
contingencies that might be reasonably anticipated, because this would
avoid the `one size fits all' problem, where a prescriptive analytical
methodology does not fit with a particular system configuration. EEI
believes that this flexible approach would provide a more effective
planning tool for the industry, while satisfying the Commission's
concerns over potentially inadequate reactive reserves. MRO notes that
the need for, and method of providing for, reactive resources varies
greatly, and if this Reliability Standard is expanded it must be done
carefully. MRO believes that all entities should not be required to
follow the same methodology to accomplish the goal of a reliable
system.
(b) Commission Determination
1869. In the NOPR, the Commission expressed concern that the
technical requirements containing terms such as ``established limits''
or ``sufficient reactive resources'' are not definitive enough to
address voltage instability and ensure reliable operations.\475\ To
address this concern, the NOPR proposed directing the ERO to modify
VAR-001-1 to include more detailed and definitive requirements on
``established limits'' and ``sufficient reactive resources'' and
identify acceptable margins (i.e. voltage and/or reactive power
margins) above voltage instability points to prevent voltage
instability and to ensure reliable operations. We will keep this
direction, and direct the ERO to include this modification in this
Reliability Standard.
---------------------------------------------------------------------------
\475\ See NOPR at P 1140.
---------------------------------------------------------------------------
1870. We recognize that our proposed modification does not identify
what definitive requirements the Reliability Standard should use for
``established limits'' and ``sufficient reactive resources.'' Rather,
the ERO should develop appropriate requirements that address the
Commission's concerns through the ERO Reliability Standards development
process. The Commission believes that the concerns of Dynegy, EEI and
MISO are best addressed by the ERO in the Reliability Standards
development process.
1871. In response to EEI's concerns about a prescriptive analytical
methodology, we clarify that the Commission is not asking that the
Reliability Standard dictate what methodology must be used to determine
reactive power needs. Rather, the Commission believes that the
Reliability Standard would benefit from having more defined
requirements that clearly define what voltage limits are used and how
much reactive resources are needed to ensure voltage instability will
not occur under normal and emergency conditions. For example, in the
NOPR, the Commission suggested that NERC consider WECC's Reliability
Criteria, which contain specific and definitive technical requirements
on voltage and margin application. While we are not directing that the
WECC reliability criteria be adopted, we believe they represent a good
example of clearly-defined requirements for voltage and reactive
margins.
1872. In sum, the Commission believes that minimum requirements for
voltage levels and reactive resources should be clearly defined by
placing more detailed requirements on the terms ``established limits''
and ``sufficient reactive resources'' in the Reliability Standard as
discussed in the NOPR and the Staff Preliminary Assessment. As
mentioned above, EEI's concerns should be considered in the ERO's
Reliability Standards development process.
iv. Periodic Voltage Stability Analysis in Real-Time Operations
(a) Comments
1873. SDG&E supports the NOPR recommendation that a more effective
requirement could be based on WECC's reliability criteria, which
contain specific and definitive technical requirements on voltage and
margin application. MidAmerican and PacifiCorp recommend that the
``WECC Methods to address voltage stability and settling margins''
should be consulted when designing corresponding NERC requirements.
1874. Xcel Energy recommends that this proposed modification
instead address requirements to measure reactive power margin for a
variety of topology conditions. MidAmerican recommends that the
Commission's proposal be modified to require real-time checks for
voltage stability assessments only in areas susceptible to voltage
instability. Alternatively, MidAmerican suggests that the Commission
``should exempt from these requirements areas that can demonstrate they
are not susceptible to voltage instability.''
1875. APPA, SDG&E and EEI all state that they are not aware of
commercially-available tools to provide real-time transient stability
assessments as part of an integrated energy management system for
operators. APPA notes that
[[Page 16591]]
premature reliance on various tools that are now under development but
not yet operational may jeopardize reliability by providing operators
with a false sense of security and recommends leaving the decision to
use such tools to NERC. EEI points out that any tools to conduct the
analyses recommended by the Commission will require adjustments and
modifications to improve their capabilities. Therefore, EEI recommends
that the Commission consider its proposals regarding these standards as
long-term industry objectives and of a lower priority than other
Reliability Standards. In addition, it is unclear to EEI whether the
proposed voltage stability assessments apply to steady-state or dynamic
analyses, or whether these assessments are of a general nature. Since
these analyses are technically complex and involve a broad range of
assumptions regarding system configurations, EEI suggests that the
Commission provide further guidance.
(b) Commission Determination
1876. In response to the concerns of APPA, SDG&E and EEI on the
availability of tools, the Commission recognizes that transient voltage
stability analysis is often conducted as an offline study, and that
steady-state voltage stability analysis can be done online. The
Commission clarifies that it does not wish to require anyone to use
tools that are not validated for real-time operations. Taking these
comments into consideration, the Commission clarifies its proposed
modification from the NOPR. For the Final Rule, we direct the ERO,
through its Reliability Standards development process, to modify
Reliability Standard VAR-001-1 to include Requirements to perform
voltage stability analysis periodically, using online techniques where
commercially-available, and offline simulation tools where online tools
are not available, to assist real-time operations. The ERO should
consider the available technologies and software as it develops this
modification to VAR-001-1 and identify a process to assure that the
Reliability Standard is not limiting the application of validated
software or other tools.
1877. With respect to MidAmerican's suggestion of exempting areas
that are not susceptible to voltage instability from the requirement to
perform voltage stability analysis, the Commission notes that such
exemption is not appropriate. We draw an analogy between transient
stability limits and voltage stability limits. The requirement to
perform voltage stability analysis is similar to existing operating
practices for IROLs that are dictated by transient stability. Transient
stability IROLs are determined using the results of off-line simulation
studies, and no areas are exempt. In real-time operations, these IROLs
are monitored to ensure that they are not violated. Similarly, voltage
stability is conducted in the same manner, determining limits with off-
line tools and monitoring limits in real-time operations. Areas that
are susceptible to voltage instability are expected to run studies
frequently, and areas that have not been susceptible to voltage
instability are expected to periodically update their study results to
ensure that these limits are not encountered during real-time
operations.
v. Controllable Load
(a) Comments
1878. SMA supports adoption of the proposal to include controllable
load as a reactive resource. SMA notes that its members' facilities
often include significant capacitor banks, and further, reducing load
can reduce local reactive requirements.
1879. SoCal Edison suggests caution regarding the Commission's
proposal to include controllable load as a reactive resource. It agrees
that, when load is reduced, voltage will increase and for that reason
controllable load can lessen the need for reactive power. However,
SoCal Edison believes that controllable load is typically an energy
product and there are other impacts not considered by the Commission's
proposal to include controllable load as a reactive resource. For
example, activating controllable load for system voltage control
lessens system demand, requiring generation to be backed down. It is
not clear to SoCal Edison whether any consideration has been given to
the potential reliability or commercial impacts of the Commission's
proposal.
(b) Commission Determination
1880. The Commission noted in the NOPR that in many cases, load
response and demand-side investment can reduce the need for reactive
power capability in the system.\476\ Based on this assertion, the
Commission proposed to direct the ERO to include controllable load
among the reactive resources to satisfy reactive requirements for
incorporation into Reliability Standard VAR-001-1. While we affirm this
requirement, we expect the ERO to consider the comments of SoCal Edison
with regard to reliability and SMA in its process for developing the
technical capability requirements for using controllable load as a
reactive resource in the applicable Reliability Standards.
---------------------------------------------------------------------------
\476\ See FERC Staff Report, Principles of Efficient and
Reliable Reactive Power Supply and Consumption (2005), available at
http://www.ferc.gov/legal/staff-reports.asp.
---------------------------------------------------------------------------
vi. Summary of Commission Determination
1881. Accordingly, the Commission approves Reliability Standard
VAR-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, the
Commission directs the ERO to develop a modification to VAR-001-1
through the Reliability Standards development process that: (1) Expands
the applicability to include reliability coordinators and LSEs; (2)
includes detailed and definitive requirements on ``established limits''
and ``sufficient reactive resources'' as discussed above, and
identifies acceptable margins above the voltage instability points; (3)
includes Requirements to perform voltage stability analysis
periodically, using online techniques where commercially available and
offline techniques where online techniques are not available, to assist
real-time operations, for areas susceptible to voltage instability; (4)
includes controllable load among the reactive resources to satisfy
reactive requirements and (5) addresses the power factor range at the
interface between LSEs and the transmission grid.
b. VAR-002-1
1882. Reliability Standard VAR-002-1 requires generator operators
to operate in automatic voltage control mode, to maintain generator
voltage or reactive power output as directed by the transmission
operator, and to notify the transmission operator of a change in status
or capability of any generator reactive power resource. The Reliability
Standard requires generator owners to provide transmission operators
with settings and data for generator step-up transformers. In the NOPR,
the Commission stated its belief that Reliability Standard VAR-002-1 is
just, reasonable, not unduly discriminatory or preferential and in the
public interest; and proposed to approve it as mandatory and
enforceable.
i. Comments
1883. APPA and SDG&E agree that VAR-002-1 is sufficient for
approval as a mandatory and enforceable Reliability Standard.
1884. Dynegy believes that VAR-002-1 should be modified to require
more detailed and definitive requirements when defining the time frame
associated with an ``incident'' of non compliance (i.e., each 4-second
scan, 10-minute
[[Page 16592]]
integrated value, hourly integrated value). Dynegy states that, as
written, this Reliability Standard does not define the time frame
associated with an ``incident'' of non-compliance, but apparently
leaves this decision to the transmission operator. Dynegy believes that
either more detail should be added to the Reliability Standard to cure
this omission, or the Reliability Standard should require the
transmission operator to have a technical basis for setting the time
frame that takes into account system needs and any limitations of the
generator. Dynegy believes that this approach will eliminate the
potential for undue discrimination and the imposition of overly
conservative or excessively wide time frame requirements, both of which
could be detrimental to grid reliability.
ii. Commission Determination
1885. In the NOPR, the Commission commended NERC and industry for
its efforts in expanding on the Requirements of VAR-002-1 from the
predecessor standard, and noted that the submitted Reliability Standard
includes Measures and Levels of Non-Compliance to ensure appropriate
generation operation to maintain network voltage schedules.
Accordingly, the Commission approves Reliability Standard VAR-002-1 as
mandatory and enforceable.
1886. Dynegy has suggested an improvement to Reliability Standard
VAR-002-1, and NERC should consider this in its Reliability Standards
development process.
14. Glossary of Terms Used in Reliability Standards
1887. NERC's glossary is updated whenever a new or revised
Reliability Standard is approved that includes a new defined term. The
glossary may also be approved by a separate action using NERC's
Reliability Standards development process. NERC updated the glossary in
its August 28, 2006 Supplemental Filing.
1888. In the NOPR, the Commission proposed to approve the glossary.
In addition, the Commission proposed to direct NERC to submit a
modification to the glossary that: (1) Includes the statutory
definitions of Bulk-Power System, Reliable Operation, and Reliability
Standard, as set forth in section 215(a) of the FPA; (2) modifies the
definitions of ``transmission operator'' and ``generator operator'' to
include aspects unique to ISOs, RTOs and pooled resource organizations;
(3) modifies the definition of ``bulk electric system'' consistent with
discussion in the NOPR Common Issues section \477\ and (4) modifies the
definition of terms concerning reserves (such as operating reserves) to
include DSM, including controllable load.
---------------------------------------------------------------------------
\477\ NOPR at P 42-43.
---------------------------------------------------------------------------
a. Comments
1889. NERC supports the Commission's proposal to approve the
glossary. APPA supports the Commission's proposal to have NERC
incorporate the statutory definitions of the terms Bulk-Power System,
Reliable Operation and Reliability Standard into the NERC glossary, as
an aide to the development of future NERC Reliability Standards.
1890. APPA suggests that the Commission permit NERC and industry to
consider whether any modifications to the terms ``transmission
operator'' and ``generation operator'' are needed, rather than
directing NERC to modify these terms. APPA's initial reaction is that
the existing terms are adequate and accommodate most elements of ISO,
RTO and pooled resource organization operations. APPA believes that a
broader and continuing inquiry is required to address such situations.
APPA anticipates that many such concerns will arise as NERC and the
Regional Entities implement the initial compliance program in June
2007, and states that any additional changes to the glossary should be
driven by that experience.
1891. APPA's concerns regarding the Commission proposal to modify
the definition of terms concerning reserves to include DSM (including
controllable load) are discussed above in reference to the BAL
Reliability Standards.
1892. NERC supports the Commission's proposal to direct NERC to
complete the necessary improvements to the proposed Reliability
Standards through the established NERC Reliability Standards
development process.
1893. Santa Clara submits that, to eliminate any ambiguity about
when these definitions of these commonly-used terms apply, a footnote
should be added to the glossary that states that the definitions
contained in the glossary are not intended to supersede any definitions
in a tariff or contract approved or accepted by the Commission.
b. Commission Conclusion
1894. The Commission approves the glossary. The terms defined in
the glossary have an important role in establishing consistent
understanding of the Reliability Standards Requirements and
implementation. The approval of the glossary will provide continuity in
application of the glossary definitions industry-wide, and will
eliminate multiple interpretations of the same term or function, which
may otherwise create miscommunication and jeopardize Bulk-Power System
reliability. The glossary should be updated through the Reliability
Standards development process whenever a new or revised Reliability
Standard that includes a new defined term is approved, or as needed to
clarify compliance activities. For example, the ERO will need to update
the glossary to reflect modifications required by the Commission in
this Final Rule.\478\
---------------------------------------------------------------------------
\478\ See, e.g., MOD-001-0, TOP-002-1 and the INT Reliability
Standards.
---------------------------------------------------------------------------
1895. The Commission directs the ERO to modify the glossary through
the Reliability Standards development process to include the statutory
definitions of the terms Bulk-Power System, Reliable Operation and
Reliability Standard. However, this determination does not negate our
discussion in the Applicability section of the Final Rule. While the
glossary should be revised to include the stautory definition of Bulk-
Power System, the Reliability Standards refer to the bulk electric
system, which is also defined in the glossary.
1896. The Commission directs the ERO to submit a modification to
the glossary that enhances the definitions of ``transmission operator''
and ``generator operator'' to reflect concerns of the commenters and
the direction provided by the Commission in other sections of this
Final Rule. The Commission is concerned that there not be any gaps or
unecessary overlaps of responsibilities concerning any of the
Requirements in the Reliability Standards that are applicable to
transmission operators and generator operators.
1897. Further, we adopt the NOPR proposal to require the ERO to
submit a modification to the glossary that updates the definition of
``operating reserves,'' as required in our discussion of BAL-002-0 and
BAL-005-0.
1898. Regarding Santa Clara's concern about terms in the glossary
differing from definitions in tariffs, we clarify that the glossary
governs Reliability Standards, while tariff definitions govern tariff
issues. We recognize that many items have different tariff definitions
from those in the NERC glossary. However, we expect most of these terms
to be consistent. If the glossary definition creates a conflict between
the Reliability Standards and a Transmission Organization's function,
[[Page 16593]]
rule, order, tariff, rate schedule, or agreement accepted, approved, or
ordered by the Commission, then the Transmission Organization shall
expeditiously notify the Commission, the Electric Reliability
Organization and the relevant Regional Entity of the possible conflict
pursuant to Sec. 39.6 of the Commission's regulations.\479\
---------------------------------------------------------------------------
\479\ 18 CFR 39.6 (2006).
---------------------------------------------------------------------------
1899. In conclusion, the Commission approves the glossary. Further,
pursuant to section 215(d)(5) of the FPA and Sec. 39.5(f) of our
regulations, the Commission directs ERO to modify the glossary through
the Reliability Standards development process to: (1) Include the
statutory definitions of the terms Bulk-Power System, Reliable
Operation and Reliability Standard; (2) modify the definition of
``transmission operator'' and ``generator operator'' to include aspects
unique to ISO, RTO and pooled resource organizations and (3) modify the
definition of ``operating reserves'' as discussed in BAL-002-0 and BAL-
005-0.
III. Information Collection Statement
1900. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\480\ The information collection
requirements in this Final Rule are identified under the Commission
data collection, FERC-725A ``Bulk Power System Mandatory Reliability
Standards.'' Under section 3507(d) of the Paperwork Reduction Act of
1995,\481\ the proposed reporting requirements in the subject
rulemaking will be submitted to OMB for review. Interested persons may
obtain information on the reporting requirements by contacting the
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426 (Attention: Michael Miller, Office of the Executive Director,
202-502-8415) or from the Office of Management and Budget (Attention:
Desk Officer for the Federal Energy Regulatory Commission, fax: 202-
395-7285, e-mail: oira_submission@omb.eop.gov).
---------------------------------------------------------------------------
\480\ 5 CFR 1320.11.
\481\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------
1901. The ``public protection'' provisions of the Paperwork
Reduction Act of 1995 requires each agency to display a currently valid
control number and inform respondents that a response is not required
unless the information collection displays a valid OMB control number
on each information collection or provides a justification as to why
the information collection number cannot be displayed. In the case of
information collections published in regulations, the control number is
to be published in the Federal Register.
1902. Public Reporting Burden: In the NOPR, the Commission based
its initial estimates on the premise that the proposed Reliability
Standards have already been in effect for a substantial period of time
on a voluntary basis and consequently entities would have already put
them into practice. Seventy of the 125 commenters express concern with
the burden to be imposed by the NOPR's requirements. The majority of
these comments address the potential impact the requirements would have
on small entities but did not provide specific estimates on this
impact. Because these comments are also the subject of the analysis
performed under the Regulatory Flexibility Act, the Commission has
provided a response under that section of this rulemaking. Commenters
also raise concerns about the impact of specific Reliability Standards,
and the Commission has addressed those concerns in the discussion of
each Reliability Standard. Five commenters, Reliant, TAPS, Wisconsin
Electric, Portland General and WECC questioned the Commission's initial
burden estimates as contained in the NOPR.
1903. By Reliant's estimate, it would take at least four employees
to prepare and submit compliance filings and to monitor compliance on
an on-going basis. TAPS, while not providing a specific estimate on the
burden, believes that the NOPR's proposed application of mandatory
Reliability Standards is overly-broad and would encompass several
thousand municipal systems. Wisconsin Electric states that the NOPR
significantly understated the impact that would be imposed by mandatory
Reliability Standards. Wisconsin Electric believes that a ``typical
control area utility with its multiple functional entity
responsibilities'' will need far more than the 100 hours estimated by
the Commission to manage a quality compliance program as discussed in
the ERO's Sanction Guidelines.\482\
---------------------------------------------------------------------------
\482\ Wisconsin Electric at 9.
---------------------------------------------------------------------------
1904. Portland General believes that meeting the Requirements of
mandatory Reliability Standards will place an additional burden for
documentation, over and above compliance with the substance of the
Requirements. It claims that the NOPR failed to take this additional
burden into account in its cost estimate for compliance. WECC disagrees
with the Commission's estimate that compliance cost would be $40
million annually on an aggregate basis. It also disagrees with the
Commission's assumption that there would be no increased reporting
burden or additional information requirements because the Reliability
Standards impose new documentation requirements that will create
additional costs.
1905. In response to the comments and upon further review we have
revised our initial estimates as reflected in the table below. While
the ERO has submitted several new Reliability Standards and included
additional Measures for documenting compliance with 20 existing
Reliability Standards, we continue to believe that the reporting
requirements embedded in the Reliability Standards that are approved in
the Final Rule have been implemented on a voluntary basis for many
years in most instances.\483\ This would not apply, however, to
entities that are new to reliability oversight. We encourage entities
that are responsible for compliance with mandatory Reliability
Standards to develop a quality compliance program as discussed in the
ERO's Sanction Guidelines. However, we believe that the costs of such a
program are distinct from the reporting burdens that are estimated
below.
---------------------------------------------------------------------------
\483\ NOPR at P 1157.
---------------------------------------------------------------------------
1906. Further, our estimates below reflect a revision in the number
of respondents, based on our determinations regarding
``applicability,'' as discussed in section II.C above.
1907. Total Annual Hours for Collection:
----------------------------------------------------------------------------------------------------------------
Number of Number of Hours per Total annual
Data collection respondents responses response hours
----------------------------------------------------------------------------------------------------------------
FERC-725A
Investor Owned Utilities.................... 170 1 2,080 353,600
Municipals and Cooperatives--Large.......... 80 1 1,420 113,600
Municipals and Cooperatives--Small.......... 670 1 710 475,700
Generator Operators......................... 360 1 500 180,000
[[Page 16594]]
Power Marketers............................. 159 1 100 15,900
Recordkeeping............................... Investor Owned Utilities .............. 35,360
Munis/Coops (Large) .............. 11,360
Munis/Coops (Small) .............. 47,570
Generator Owner/Ops. .............. 18,000
Power Marketers .............. 1,590
Totals.................................. .............. .............. .............. 1,252,680
----------------------------------------------------------------------------------------------------------------
(FTE=Full Time Equivalent or 2,080 hours)
Total Hours = 1,138,800 (reporting) + 113,880 (recordkeeping) =
1,252,680 hours. This estimated reporting burden will be significantly
reduced once joint action agencies are established, which will reduce
the number of small entities that will be responsible for compliance
with Reliability Standards.
1908. Information Collection Costs: The Commission sought comments
about the costs needed to comply with these requirements. As noted
above, a number of commenters state that the NOPR underestimated the
burden of the rulemaking in terms of hours required to comply. However,
no comments were received regarding the Commission's estimate of the
projected cost of $200/hour to comply with these requirements. In
further consideration, the Commission believes that the $200/hour
projection is too high, and the calculations below reflect an adjusted
hourly figure.
Cost to Comply:
hour), consultant ($150), technical ($80) and administrative support
($25)).
Total Costs: Reporting ($129,823,200) + Recordkeeping ($1,935,960)
= $131,759,160.
Sources: ``NERC Compliance Update: What it might cost to comply'',
Herb Schrayshuen, NARUC-Electric Reliability Staff Subcommittee,
November 12, 2006.
Janco Associates, Inc., 2005 Information Technology Compensation
Study, January 2005.
Bureau of Labor Statistics, Department of Labor, Occupational
Outlook Handbook, http://www.bls.gov/oco/ocos268.htm.
Titles: FERC-725A ``Mandatory Reliability Standards for the Bulk-
Power System''.
Action: Proposed Collection of Information.
OMB Control Nos: To be determined.
Respondents: Business or other for profit, not for profit
institutions, state, local or tribal government and Federal Government.
Frequency of Responses: On occasion.
Necessity of Information: The Final Rule approves 83 Reliability
Standards. Compliance with such Reliability Standards will be mandatory
and enforceable for the applicable categories of entities identified in
each Reliability Standard. These Reliability Standards are approved by
the Commission pursuant to its authority under section 215 of the FPA,
which authorizes the Commission to approve a Reliability Standard
proposed by the ERO if the Commission determines that it is just and
reasonable, not unduly discriminatory or preferential and in the public
interest. The Reliability Standards approved in this Final Rule are
necessary for the reliable operation of the nation's interconnected
Bulk-Power System.
For information on the requirements, submitting comments on the
collection of information and the associated burden estimates including
suggestions for reducing this burden, please send your comments to the
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426 (Attention: Michael Miller, Office of the
Executive Director, 202-502-8415) or send comments to the Office of
Management and Budget (Attention: Desk Officer for the Federal Energy
Regulatory Commission, fax: 202-395-7285, e-mail
oira_submission@omb.eop.gov).
IV. Environmental Analysis
1909. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\484\ The
actions taken here fall within the categorical exclusion in the
Commission's regulations for rules that are clarifying, corrective or
procedural, for information gathering, analysis, and
dissemination.\485\
---------------------------------------------------------------------------
\484\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
\485\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------
V. Regulatory Flexibility Act
1910. The Regulatory Flexibility Act of 1980 (RFA)\486\ generally
requires a description and analysis of Final Rules that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking. It
only requires consideration of alternatives that are less burdensome to
small entities and an agency explanation of why alternatives were
rejected.
---------------------------------------------------------------------------
\486\ 5 U.S.C. 601-612 (2006).
---------------------------------------------------------------------------
1911. In drafting a rule an agency is required to: (1) Assess the
effect that its regulation will have on small entities; (2) analyze
effective alternatives that may minimize a regulation's impact and (3)
make the analyses available for public comment.\487\ In its NOPR, the
agency must either include an initial regulatory flexibility analysis
(initial RFA) \488\ or certify that the proposed rule will not have a
``significant impact on a substantial number of small entities.'' \489\
---------------------------------------------------------------------------
\487\ 5 U.S.C. 601-604.
\488\ 5 U.S.C. 603(a).
\489\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------
1912. If in preparing the NOPR an agency determines that the
proposal could have a significant impact on a substantial number of
small entities, the agency shall ensure that small entities will have
an opportunity to participate in the rulemaking procedure.\490\
---------------------------------------------------------------------------
\490\ 5 U.S.C. 609(a).
---------------------------------------------------------------------------
1913. In its Final Rule, the agency must also either prepare a
Final Regulatory Flexibility Analysis (Final RFA) or make the requisite
certification. Based on the comments the agency receives on the NOPR,
it can alter its original position as expressed in the NOPR but it is
not required to make any substantive changes to the proposed
regulation.
1914. The statute provides for judicial review of an agency's final
certification or Final RFA.\491\ An agency must file a
[[Page 16595]]
Final RFA demonstrating a ``reasonable, good-faith effort'' to carry
out the RFA mandate.\492\ However, the RFA is a procedural, not a
substantive, mandate. An agency is only required to demonstrate a
reasonable, good faith effort to review the impact the proposed rule
would place on small entities, any alternatives that would address the
agency's and small entities' concerns and their impact, provide small
entities the opportunity to comment on the proposals, and review and
address comments. An agency is not required to adopt the least
burdensome rule. Further, the RFA does not require an agency to assess
the impact of a rule on all small entities that may be affected by the
rule, only on those entities that the agency directly regulates and
that will be directly impacted by the rule.\493\
---------------------------------------------------------------------------
\491\ 5 U.S.C. 611.
\492\ United Cellular Corp. v. FCC, 254 F.3d 78, 88 (D.C. Cir.
2001); Alenco Commuications, Inc. v. FCC, 201 F.3d 608, 625 (5th
Cir. 2000).
\493\ Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327 (D.C.
Cir 1985).
---------------------------------------------------------------------------
A. Notice of Proposed Rulemaking
1915. In the NOPR, the Commission stated that the proposed
Reliability Standards ``may cause some small entities to experience
significant economic impact.'' \494\ In response to the ERO's proposal
to develop limits on the applicability of specific Reliability
Standards, the Commission stated that, while it could not rule on the
merits until a specific proposal is submitted, the Commission stated
that it believed that reasonable limits based on size may be an
acceptable alternative to ``lessen the economic impact on the proposed
rule on small entities.'' \495\ The Commission emphasized that any such
limits must not weaken Bulk-Power System reliability.
---------------------------------------------------------------------------
\494\ NOPR at P 1175.
\495\ Id. at 1176.
---------------------------------------------------------------------------
1916. Further, under the Applicability Issues section of the NOPR,
we devoted an entire subsection to the issues facing small
entities.\496\ The Commission stated that there may be instances in
which small entity compliance with a particular Reliability Standard
may be critical to reliability. It explained that, in such
circumstances, it may be appropriate to differentiate among subsets of
users, owners and operators. As an example, the NOPR provided that
``the requirement to have adequate communications capabilities to
address real-time emergency conditions * * * 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.'' \497\ Additionally, in the NOPR, the
Commission supported the ERO's proposal to permit the registration of
``joint action agencies,'' a concept designed to ease the burden of
small entities by allowing one organization to perform reliability-
related activities for multiple entities. The Commission proposed to
direct the ERO to develop procedures that would permit a joint action
agency or similar organization to accept compliance responsibility on
behalf of its members.
---------------------------------------------------------------------------
\496\ Id. at 49-53 (Section B.3 ``Applicability to Small
Entities'').
\497\ Id. at 51.
---------------------------------------------------------------------------
1917. Thus, in the NOPR, the Commission discussed the potential
disparate impact on small entities, considered the implications and
potential alternatives and solicited comments on the limiting the
application of the Reliability Standards to small entities. Further,
the Information Collection Statement discussed the difficulty
estimating the number of small entities that would be affected by the
Reliability Standards. As such, the Commission was aware of the
potential impacts on small entities and was actively considering
alternatives that would lessen the impact on them while still ensuring
reliability of the Bulk-Power System.
1. Comments
1918. APPA and NRECA, in their joint comments, provide data about
their membership. APPA states that, based on 2005 data, 1,971 public
utilities or 98 percent of the public utilities in the United States
had less than 4 million MW hours in sales which would qualify them as
small entities. Of these, 90 percent--or 1,775--are distribution-only
utilities, 48 are wholesale-only, and 148 make both wholesale and
retail sales.\498\ NRECA states that its membership includes 930 rural
cooperatives most of which are distribution utilities and almost all of
which would qualify as small entities. Additionally, according to
NRECA, 40 of its 65 generation and transmission cooperatives also
qualify as small entities.\499\
---------------------------------------------------------------------------
\498\ APPA/NRECA comments at 2.
\499\ Id.
---------------------------------------------------------------------------
1919. APPA/NRECA contends that the Commission did not include a
complete initial RFA analysis as required and, without a full initial
RFA, the Commission cannot lay a proper foundation for eliciting public
comments on the impacts of the rule on small entities. Specifically,
APPA/NRECA contends that the NOPR failed to include proposals that
would minimize the impact on small entities. They assert that, instead,
the Commission's proposed definition of bulk electric system in the
NOPR exceeds NERC's definition and thereby sweeps in many small
facilities that are unnecessary to the Reliable Operation of the Bulk-
Power System. APPA/NRECA argue that, if the Commission adopts this
definition, many small transmission owners and operators of lower
voltage transmission systems will be unnecessarily required to bear the
increased training costs to comply with Reliability Standards, yet the
NOPR never considered these additional burdens. APPA/NRECA also asserts
that, under this definition, many small distribution providers would
also be required to comply with the communication-related (COM)
Reliability Standards at additional costs that were never discussed.
They request that the Commission address these shortcomings.
1920. APPA/NRECA also claims that the Commission substantially
underestimated the number of small entities that would be impacted by
the application of the Reliability Standards as proposed in the NOPR.
APPA/NRECA asserts that 98 percent of public utilities and 99 percent
of public cooperatives, along with numerous small industrial
facilities, small qualifying facilities and small generators would
qualify under the small entity definition and would be impacted by the
rule. According to APPA/NRECA, most of these small entities would not
have a material impact on the reliability of the Bulk-Power System but,
under the NOPR's definition of Bulk-Power System, would be required to
comply with the Reliability Standards.
1921. APPA/NRECA suggests that the Commission can significantly
reduce the impact on small entities by ``focusing on materiality.''
They contend that an overly-expansive reliability regime would violate
the FPA by imposing unnecessary regulatory burdens on small entities
and divert the ERO's and the Commission's resources away from those
entities that are crucial to Bulk-Power System reliability. APPA/NRECA
asserts that the Commission can ensure reliability without
unnecessarily burdening small entities by considering two alternatives.
First, they urge the Commission to adopt NERC's current definition of
bulk electric system. Second, they ask the Commission to reconsider the
standard-by-standard approach to defining owners, users and operators
of the Bulk-Power System and, instead, accept the NERC compliance
registry to identify the entities that will be responsible for
compliance with Reliability Standards. APPA/NRECA, TAPS, and numerous
[[Page 16596]]
other commenters discuss these proposals in their comments, which the
Commission addresses in the Applicability Issues section of the Final
Rule.\500\
---------------------------------------------------------------------------
\500\ See Applicability Issues: Bulk-Power System v. Bulk
Electric System and Applicability to Small Entities, supra sections
II.C.1-2.
---------------------------------------------------------------------------
1922. TAPS asserts that the Commission should apply the ERO's
registration thresholds and, ``absent such limits, the Commission
cannot satisfy its obligations under the [RFA].'' \501\ Georgia Cities
asserts that the Commission should adopt reasonable limits on the
application of the Reliability Standards to small entities, as it
promised in its RFA statement.
---------------------------------------------------------------------------
\501\ TAPS at 13.
---------------------------------------------------------------------------
2. Commission Response
1923. The Commission believes that the NOPR provided a meaningful
discussion of the impact that the Reliability Standards could have on
small entities and discussed several potential alternatives. In fact,
the NOPR contained an entire section on the applicability of the
proposed standards on small entities.\502\ In that section, the
Commission discussed various alternatives to lessen the acknowledged
potential impact on small entities. The Commission indicated its
receptiveness to the ERO's proposal to develop threshold limits
regarding the applicability of specific Reliability Standards. The
Commission also suggested that, where it is necessary for reliability
that a Reliability Standard apply to small entities, implementation of
the requirements of such Reliability Standards may vary based on size
or role. In the NOPR, the Commission set forth another alternative to
address the potential burden on small entities when it proposed to
direct the ERO to develop procedures permitting a joint action agency
or similar organization to accept compliance responsibility on behalf
of its members.
---------------------------------------------------------------------------
\502\ NOPR at P 49-53.
---------------------------------------------------------------------------
1924. As previously stated, the purpose of the RFA is to ensure
that agencies consider the impact a proposed rule would have on small
entities and any potential alternatives that would minimize that
impact. The initial RFA analysis is designed to elicit informed
comments on the impacts to small entities and alternatives. The
Commission believes the NOPR achieved this goal. After the NOPR was
issued, the Commission received over 125 comments and a majority of
those addressed small entity issues. Further, almost all of the
commenters addressed the NOPR's proposed interpretation of the
definition of the bulk electric system, which as APPA/NRECA states
would have had the greatest impact on small entities.
1925. In addition to the comments received addressing these issues,
Commission staff has met with representatives of small entities,
including APPA and NRECA, and listened to their concerns on the
potential impacts of the Final Rule and discussed possible
alternatives.
1926. Since receiving APPA/NRECA's comments on the RFA, the
Commission has compiled and reviewed available data on small entities
and the impact of the Final Rule on such entities. Therefore, the
Commission believes that any inadequacy that may have existed in the
NOPR's initial RFA analysis has now been corrected. This Final RFA and
the alternative proposals adopted herein demonstrate the Commission's
consideration of the potential burdens that the rulemaking could place
on small entities.
1927. As discussed in the Applicability section above, the
Commission adopts in the Final Rule the current definition of bulk
electric system. Any possible change to the definition would occur in a
future Commission proceeding. Further, the Commission has endorsed the
ERO's compliance registry process to identify the entities that must
comply with mandatory Reliability Standards.\503\ By adopting these
alternative proposals, the Commission has been responsive to small
entity concerns and greatly reduced the number of small entities that
will be affected by the Final Rule.
---------------------------------------------------------------------------
\503\ As noted previously, APPA, NRECA and TAPs submitted
supplemental comments supporting the ERO's compliance registry
process.
---------------------------------------------------------------------------
B. Final RFA
1. Description of the Reasons Why Action by the Agency Is Being
Considered
1928. On April 4, 2006, as later modified and supplemented, NERC--
the ERO--submitted 107 Reliability Standards for Commission approval
pursuant to section 215(d) of the FPA. The ERO's submission includes
the ``Version 0'' standards with which the electric industry has
complied on a voluntary basis as well as several new Reliability
Standards approved by NERC since its certification as the ERO.
1929. As set forth in section 215(a) of the FPA, the term
``Reliability Standard'' means a requirement, approved by the
Commission to provide for the Reliable Operation of the Bulk-Power
System. The term ``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, or
cascaded failures of such system will not occur as a result of a sudden
disturbance * * * or unanticipated failure of system elements.'' \504\
Thus, the purpose of each Reliability Standard approved by the
Commission in this Final Rule is to provide for the Reliable Operation
of the Bulk-Power System and thereby minimize the risk of instability,
uncontrolled or cascading failure on the Bulk-Power System.
---------------------------------------------------------------------------
\504\ 16 U.S.C. 824o(a)(4) (2006).
---------------------------------------------------------------------------
1930. The Commission is approving 83 of the proposed Reliability
Standards. Upon the effective date of the Final Rule, compliance with
these Reliability Standards will be mandatory and enforceable for
applicable users, owners and operators of the Bulk-Power System. The
Commission believes that these Reliability Standards form a solid
foundation on which to develop and maintain the reliability of the
North American Bulk-Power System.
2. Objectives of and the Legal Basis for the Final Rule
1931. This Final Rule requires applicable users, owners and
operators of the Bulk-Power System to comply with mandatory and
enforceable Reliability Standards. As discussed above, these
Reliability Standards are necessary to ensure the reliable operation of
the North American Bulk-Power System.
1932. EPAct 2005 added a new section 215 to the FPA, which provides
for a system of mandatory and enforceable Reliability Standards.
Section 215(d)(1) of the FPA provides that the ERO must file each
Reliability Standard or modification to a Reliability Standard that it
proposes to be made effective, i.e., mandatory and enforceable, with
the Commission. As mentioned above, on April 4, 2006, and as later
modified and supplemented, the ERO submitted 107 Reliability Standards
for Commission approval pursuant to section 215(d) of the FPA.
1933. Section 215(d)(2) of the FPA provides that the Commission may
approve, by rule or order, a proposed Reliability Standard or
modification to a proposed Reliability Standard if it meets the
statutory standard for approval, giving due weight to the technical
expertise of the ERO. Alternatively, the Commission may remand a
Reliability Standard pursuant to section 215(d)(4) of the FPA. Further,
the Commission may order the ERO to submit to the
[[Page 16597]]
Commission a proposed Reliability Standard or a 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'' section 215 of the FPA.\505\ The Commission's action in
this Final Rule is based on its authority pursuant to section 215 of
the FPA.
---------------------------------------------------------------------------
\505\ See 16 U.S.C. 824o(d)(5) (2006).
---------------------------------------------------------------------------
3. Significant Issues Raised by Comments, Agency Assessment of the
Comments and a Statement of Any Changes Made in the Proposed Rule as a
Result of the Comments
1934. Numerous small entity commenters oppose the NOPR
interpretation of bulk electric system and urge the Commission to adopt
the ERO's current definition of that term. Further, small entity
commenters oppose the NOPR's proposal to address applicability on a
standard-by-standard basis and, instead, ask that the Commission rely
on the ERO's compliance registry process as the means to identify
entities responsible for complying with mandatory and enforceable
Reliability Standards. Commenters assert that the Commission's proposed
changes would greatly increase the number of small entities that would
be significantly impacted by the Final Rule.
1935. As discussed above, the Commission is not adopting its
proposed interpretation of bulk electric system contained in the NOPR.
Rather, the Commission adopts the NERC definition of bulk electric
system. Further, the Commission is relying on NERC's registration
process to provide as much certainty as possible regarding the
applicability and responsibility of specific entities in the start-up
phase of the mandatory Reliability Standards regime. Any change in
these approaches would be addressed in a separate Commission
proceeding.
1936. A complete summary of these comments and the Commission's
response has been previously addressed in the Applicability section.
4. Description and Estimate of the Number of Small Entities To Which
the Final Rule Will Apply
1937. According to the SBA, a small electric utility is defined as
one that has a total electric output of less than four million MWh in
the preceeding year.
1938. According to the DOE's Energy Information Administration
(EIA), there were 3,284 electric utility companies in the United States
in 2005,\506\ and 3,029 of these electric utilities qualify as small
entities under the SBA definition. Of these 3,284 electric utility
companies, the EIA subdivides them as follows: (1) 883 cooperatives of
which 852 are small entity cooperatives; (2) 1,862 municipal utilities,
of which 1842 are small entity municipal utilities; (3) 127 political
subdivisions, of which 114 are small entity political subdivisions; (4)
159 power marketers, of which 97 individually could be considered small
entity power marketers; \507\ (5) 219 privately owned utilities, of
which 104 could be considered small entity private utilities; (6) 25
state organizations, of which 16 are small entity state organizations
and (7) nine federal organizations of which four are small entity
federal organizations.
---------------------------------------------------------------------------
\506\ See Energy Information Administration Database, Form EIA-
861, Dept. of Energy (2005), available at http://www.eia.doe.gov/cneaf/electricity/page/eia861.html
.
\507\ Most of these small entity power marketers and private
utilities are affiliated with others and, therefore, do not qualify
as small entities under the SBA definition.
---------------------------------------------------------------------------
1939. As discussed above, the Commission is relying on the ERO's
compliance registry process to identify which entities must comply with
mandatory and enforceable Reliability Standards. The ERO's Compliance
Registry Criteria describe how NERC will identify organizations that
may be candidates for registration and assign them to the compliance
registry.\508\ According to this document, the ERO will register
transmission owners and operators with an integrated element associated
with the Bulk-Power System of 100 kV and above, or lower voltage as
defined by a Regional Entity. The ERO plans to register only those
distribution providers or LSEs that have a peak load of 25 MW or
greater and are directly connected to the bulk electric system or are
designated as a responsible entity as part of a required underfrequency
load shedding program or a required undervoltage load shedding program.
For generators, the ERO plans to register individual units of 20 MVA or
greater that are directly connected to the bulk electric system,
generating plants with an aggregate rating of 75 MVA or greater, any
blackstart unit material to a restoration plan, or any generator
``regardless of size, that is material to the reliability of the Bulk-
Power System.'' Further, the ERO will not register an entity that meets
the above criteria if it has transferred responsibility for compliance
with mandatory Reliability Standards to a joint action agency or other
organization.
---------------------------------------------------------------------------
\508\ See NERC Statement of Compliance Registry Criteria
(Revision 3) at 6-8.
---------------------------------------------------------------------------
1940. As mentioned above, the SBA defines a small electric utility
as one that has a total electric output of less than four million MWh
in the proceeding year. Thus, the set of small entities that must
comply with mandatory Reliability Standards would be those that exceed
the ERO registry criteria but still meet the SBA definition. The
Commission has reviewed data compiled by EIA in Form EIA-861, NERC's
pre-registry data, and information submitted by commenters, and
determined an estimate of the number of small entities to which the
Final Rule will apply.
1941. The Commission estimates that the Reliability Standards
approved in the Final Rule will apply to approximately 682 small
entities (excluding entities in Alaska and Hawaii) as follows: 670
small municipal utilities and cooperatives and 12 small investor-owned
utilities.
1942. As discussed above, the ERO's Compliance Registry Criteria
allows for a joint action agency, G&T cooperative or similar
organization to accept compliance responsibility on behalf of its
members. Once such organizations register with the ERO, the number of
small entities registered with the ERO will diminish and, thus,
significantly reduce the impact of the Final Rule on small entities.
1943. To be included in the compliance registry, the ERO will have
made a determination that a specific small entity has a material impact
on the Bulk-Power System. Consequently, the compliance of such small
entities is justifiable as necessary for Bulk-Power System reliability.
5. Description of the Projected Reporting, Recordkeeping and Other
Compliance Requirements for Small Entities
1944. A complete summary of comments and the Commission's response
has been previously addressed in the Information Collection Statement
section.
6. Duplication of Other Federal Rules
1945. There are no relevant Federal rules which may duplicate,
overlap or conflict with the Final Rule.
7. Description of Any Significant Alternatives to the Final Rule
1946. In the Final Rule, the Commission adopts several significant
alternatives that will minimize the burden on small entities. The
Commission approves the current ERO definition of bulk electric system,
which
[[Page 16598]]
will reduce significantly the number of small entities responsible for
complying with the Final Rule. The Commission also approves the ERO
compliance registry process to identify the entities responsible for
compliance with mandatory and enforceable Reliability Standards.
Further, the Commission directs the ERO to submit a procedure to permit
a joint action agency or similar organization to accept compliance
responsibility on behalf of its members. A complete summary of comments
and the Commission's response has been previously addressed in the
Applicability Section.
VI. Document Availability
1947. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, N.E., Room 2A, Washington DC 20426.
1948. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
1949. User assistance is available for eLibrary and FERC's Web site
during normal business hours from our Help line at (202) 502-8222 or
the Public Reference Room at (202) 502-8371 Press 0, TTY (202) 502-
8659. E-mail the Public Reference Room at
public.referenceroom@ferc.gov.
VII. Effective Date and Congressional Notification
1950. These regulations are effective June 4, 2007. The Commission
has determined, with the concurrence of the Administrator of the Office
of Information and Regulatory Affairs of OMB, that this rule is a
``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996.
List of Subjects in 18 CFR Part 40
Electric power; reporting and recordkeeping requirements.
By the Commission.
Philis J. Posey,
Acting Secretary.
0
In consideration of the foregoing, the Commission amends Chapter I,
Title 18, Code of Federal Regulations, by adding Part 40 to read as
follows:
PART 40--MANDATORY RELIABILITY STANDARDS FOR THE BULK-POWER SYSTEM
Sec.
40.1 Applicability.
40.2 Mandatory Reliability Standards.
40.3 Availability of Reliability Standards.
Authority: 16 U.S.C. 824o.
Sec. 40.1 Applicability.
(a) This part applies to all users, owners and operators of the
Bulk-Power System within the United States (other than Alaska or
Hawaii), including, but not limited to, entities described in section
201(f) of the Federal Power Act.
(b) Each Reliability Standard made effective by Sec. 40.2 must
identify the subset of users, owners and operators of the Bulk-Power
System to which a particular Reliability Standard applies.
Sec. 40.2 Mandatory Reliability Standards.
(a) Each applicable user, owner or operator of the Bulk-Power
System must comply with Commission-approved Reliability Standards
developed by the Electric Reliability Organization.
(b) A proposed modification to a Reliability Standard proposed to
become effective pursuant to Sec. 39.5 of this Chapter will not be
effective until approved by the Commission.
Sec. 40.3 Availability of Reliability Standards.
The Electric Reliability Organization must post on its Web site the
currently effective Reliability Standards as approved and enforceable
by the Commission. The effective date of the Reliability Standards must
be included in the posting.
Note: The following appendices will not be published in the Code
of Federal Regulations.
Appendix A.--Disposition of Reliability Standards, Glossary and Regional Differences
----------------------------------------------------------------------------------------------------------------
Reliability standard Title Proposed disposition
----------------------------------------------------------------------------------------------------------------
BAL-001-0............................. Real Power Balancing Control Performance Approve.
BAL-002-0............................. Disturbance Control Performance......... Approve; direct modification.
BAL-003-0............................. Frequency Response and Bias............. Approve; direct modification.
BAL-004-0............................. Time Error Correction................... Approve; direct modification.
BAL-005-0............................. Automatic Generation Control............ Approve; direct modification.
BAL-006-1............................. Inadvertent Interchange................. Approve; direct modification.
CIP-001-1............................. Sabotage Reporting...................... Approve; direct modification.
COM-001-1............................. Telecommunications...................... Approve; direct modification.
COM-002-2............................. Communications and Coordination......... Approve; direct modification.
EOP-001-0............................. Emergency Operations Planning........... Approve; direct modification.
EOP-002-2............................. Capacity and Energy Emergencies......... Approve; direct modification.
EOP-003-1............................. Load Shedding Plans..................... Approve; direct modification.
EOP-004-1............................. Disturbance Reporting................... Approve; direct modification.
EOP-005-1............................. System Restoration Plans................ Approve; direct modification.
EOP-006-1............................. Reliability Coordination--System Approve; direct modification.
Restoration.
EOP-007-0............................. Establish, Maintain, and Document a Pending.
Regional Blackstart Capability Plan.
EOP-008-0............................. Plans for Loss of Control Center Approve; direct modification.
Functionality.
EOP-009-0............................. Documentation of Blackstart Generating Approve.
Unit Test Results.
FAC-001-0............................. Facility Connection Requirements........ Approve.
FAC-002-0............................. Coordination of Plans for New Facilities Approve; direct modification.
FAC-003-1............................. Transmission Vegetation Management Approve; direct modification.
Program.
FAC-004-0............................. Methodologies for Determining Electrical Withdrawn.
Facility Ratings.
FAC-005-0............................. Electrical Facility Ratings for System Withdrawn.
Modeling.
FAC-008-1............................. Facility Ratings Methodology............ Approve; direct modification.
FAC-009-1............................. Establish and Communicate Facility Approve.
Ratings.
FAC-012-1............................. Transfer Capabilities Methodology....... Pending.
[[Page 16599]]
FAC-013-1............................. Establish and Communicate Transfer Approve; direct modification.
Capabilities.
INT-001-2............................. Interchange Transaction Tagging......... Approve; direct modification.
INT-002-0............................. Interchange Transaction Tag Withdrawn.
Communication and Assessment.
INT-003-2............................. Interchange Transaction Implementation.. Approve.
INT-004-1............................. Interchange Transaction Modifications... Approve.
INT-005-1............................. Interchange Authority Distributes Approve.
Arranged Interchange.
INT-006-1............................. Response to Interchange Authority....... Approve; direct modification.
INT-007-1............................. Interchange Confirmation................ Approve.
INT-008-1............................. Interchange Authority Distributes Status Approve.
INT-009-1............................. Implementation of Interchange........... Approve.
INT-010-1............................. Interchange Coordination Exceptions..... Approve.
IRO-001-1............................. Reliability Coordination-- Approve; direct modification.
Responsibilities and Authorities.
IRO-002-1............................. Reliability Coordination--Facilities.... Approve; direct modification.
IRO-003-2............................. Reliability Coordination--Wide Area View Approve; direct modification.
IRO-004-1............................. Reliability Coordination--Operations Approve; direct modification.
Planning.
IRO-005-1............................. Reliability Coordination--Current Day Approve; direct modification.
Operations.
IRO-006-3............................. Reliability Coordination--Transmission Approve; direct modification.
Loading Relief.
IRO-014-1............................. Procedures, Processes, or Plans to Approve.
Support Coordination Between
Reliability Coordinators.
IRO-015-1............................. Notifications and Information Exchange Approve.
Between Reliability Coordinators.
IRO-016-1............................. Coordination of Real-time Activities Approve.
Between Reliability Coordinators.
MOD-001-0............................. Documentation of TTC and ATC Calculation Pending; direct modification.
Methodologies.
MOD-002-0............................. Review of TTC and ATC Calculations and Pending.
Results.
MOD-003-0............................. Procedure for Input on TTC and ATC Pending.
Methodologies and Values.
MOD-004-0............................. Documentation of Regional CBM Pending; direct modification.
Methodologies.
MOD-005-0............................. Procedure for Verifying CBM Values...... Pending.
MOD-006-0............................. Procedures for Use of CBM Values........ Approve; direct modification.
MOD-007-0............................. Documentation of the Use of CBM......... Approve; direct modification.
MOD-008-0............................. Documentation and Content of Each Pending; direct modification.
Regional TRM Methodology.
MOD-009-0............................. Procedure for Verifying TRM Values...... Pending.
MOD-010-0............................. Steady-State Data for Transmission Approve; direct modification.
System Modeling and Simulation.
MOD-011-0............................. Regional Steady-State Data Requirements Pending; direct modification.
and Reporting Procedures.
MOD-012-0............................. Dynamics Data for Transmission System Approve; direct modification.
Modeling and Simulation.
MOD-013-1............................. RRO Dynamics Data Requirements and Pending; direct modification.
Reporting Procedures.
MOD-014-0............................. Development of Interconnection-Specific Pending; direct modification.
Steady State System Models.
MOD-015-0............................. Development of Interconnection-Specific Pending; direct modification.
Dynamics System Models.
MOD-016-1............................. Actual and Forecast Demands, Net Energy Approve; direct modification.
for Load, Controllable DSM.
MOD-017-0............................. Aggregated Actual and Forecast Demands Approve; direct modification.
and Net Energy for Load.
MOD-018-0............................. Reports of Actual and Forecast Demand Approve.
Data.
MOD-019-0............................. Forecasts of Interruptible Demands and Approve; direct modification.
DCLM Data.
MOD-020-0............................. Providing Interruptible Demands and DCLM Approve; direct modification.
Data.
MOD-021-0............................. Accounting Methodology for Effects of Approve; direct modification.
Controllable DSM in Forecasts.
MOD-024-1............................. Verification of Generator Gross and Net Pending.
Real Power Capability.
MOD-025-1............................. Verification of Generator Gross and Net Pending; direct modification.
Reactive Power Capability.
PER-001-0............................. Operating Personnel Responsibility and Approve.
Authority.
PER-002-0............................. Operating Personnel Training............ Approve; direct modification.
PER-003-0............................. Operating Personnel Credentials......... Approve; direct modification.
PER-004-1............................. Reliability Coordination--Staffing...... Approve; direct modification.
PRC-001-1............................. System Protection Coordination.......... Approve; direct modification.
PRC-002-1............................. Define and Document Disturbance Pending.
Monitoring Equipment Requirements.
PRC-003-1............................. Regional Requirements for Analysis of Pending.
Misoperations of Transmission and
Generation Protection Systems.
PRC-004-1............................. Analysis and Mitigation of Transmission Approve.
and Generation Protection System
Misoperations.
PRC-005-1............................. Transmission and Generation Protection Approve; direct modification.
System Maintenance and Testing.
PRC-006-0............................. Development and Documentation of Pending.
Regional UFLS Programs.
PRC-007-0............................. Assuring Consistency with Regional UFLS Approve.
Program.
PRC-008-0............................. Underfrequency Load Shedding Equipment Approve; direct modification.
Maintenance Programs.
PRC-009-0............................. UFLS Performance Following an Approve.
Underfrequency Event.
PRC-010-0............................. Assessment of the Design and Approve; direct modification.
Effectiveness of UVLS Program.
PRC-011-0............................. UVLS System Maintenance and Testing..... Approve; direct modification.
PRC-012-0............................. Special Protection System Review Pending.
Procedure.
PRC-013-0............................. Special Protection System Database...... Pending.
PRC-014-0............................. Special Protection System Assessment.... Pending.
PRC-015-0............................. Special Protection System Data and Approve.
Documentation.
PRC-016-0............................. Special Protection System Misoperations. Approve.
PRC-017-0............................. Special Protection System Maintenance Approve; direct modification.
and Testing.
[[Page 16600]]
PRC-018-1............................. Disturbance Monitoring Equipment Approve.
Installation and Data Reporting.
PRC-020-1............................. Undervoltage Load Shedding Program Pending.
Database.
PRC-021-1............................. Undervoltage Load Shedding Program Data. Approve.
PRC-022-1............................. Undervoltage Load Shedding Program Approve.
Performance.
TOP-001-1............................. Reliability Responsibilities and Approve; direct modification.
Authorities.
TOP-002-2............................. Normal Operations Planning.............. Approve; direct modification.
TOP-003-0............................. Planned Outage Coordination............. Approve; direct modification.
TOP-004-1............................. Transmission Operations................. Approve; direct modification.
TOP-005-1............................. Operational Reliability Information..... Approve; direct modification.
TOP-006-1............................. Monitoring System Conditions............ Approve; direct modification.
TOP-007-0............................. Reporting SOL and IROL Violations....... Approve.
TOP-008-1............................. Response to Transmission Limit Approve.
Violations.
TPL-001-0............................. System Performance Under Normal Approve; direct modification.
Conditions.
TPL-002-0............................. System Performance Following Loss of a Approve; direct modification.
Single BES Element.
TPL-003-0............................. System Performance Following Loss of Two Approve; direct modification.
or More BES Elements.
TPL-004-0............................. System Performance Following Extreme BES Approve; direct modification.
Events.
TPL-005-0............................. Regional and Interregional Self- Pending.
Assessment Reliability Reports.
TPL-006-0............................. Assessment Data from Regional Pending.
Reliability Organizations.
VAR-001-1............................. Voltage and Reactive Control............ Approve; direct modification.
VAR-002-1............................. Generator Operations for Maintaining Approve.
Network Voltage Schedules.
Glossary.............................. Glossary of Terms Used in Reliability Approve; direct modification.
Standards.
Regional Difference................... BAL-001:ERCOT:CPS2...................... Approve; direct modification.
Regional Difference................... BAL-006: MISO RTO inadvertent Approve.
Interchange Accounting.
Regional Difference................... BAL-006: MISO/SPP Financial Inadvertent Approve.
Settlement.
Regional Difference................... INT-001/4: WECC Tagging Dynamic Pending.
Schedules and Inadvertent Payback.
Regional Difference................... INT-001/3:MISO Energy Flow Information.. Approve.
Regional Difference................... INT-003: MISO/SPP Scheduling Agent...... Approve.
Regional Difference................... INT-003: MISO Enhanced Scheduling Agent. Approve.
Regional Difference................... IRO-006: PJM/MISO/SPP Enhanced Pending.
Congestion Management.
----------------------------------------------------------------------------------------------------------------
Appendix B.--Commenters on Notice of Proposed Rulemaking
------------------------------------------------------------------------
Abbreviation Entity
------------------------------------------------------------------------
Alberta ESO....................... Alberta Electric System Operator.
ALCOA............................. Alcoa, Inc. and Alcoa Power
Generating Company.
Allegheny......................... Allegheny Power and Allegheny Energy
Supply Company, LLC.
AMP Ohio.......................... American Municipal Power--Ohio, Inc.
APPA.............................. American Public Power Association.
APPA/NRECA........................ APPA/NRECA.
ATC............................... American Transmission Company, LLC.
Avista/Puget...................... Avista Corporation and Puget Sound
Energy, Inc.
BPA............................... Bonneville Power Administration.
CAISO............................. California Independent System
Operator Corporation.
California Cogernation............ Cogeneration Association of
California and the Energy Producers
and Users Coalition.
California PUC.................... Public Utilities Commission of the
State of California.
CEA............................... Canadian Electricity Association.
Cleveland Public Power............ City of Cleveland, Division of
Cleveland Public Power.
Comverge.......................... Comverge, Inc.
Connecticut Attorney General*..... Richard Blumenthal, Attorney General
for the State of Connecticut.
Connecticut DPUC*................. Connecticut Department of Public
Utility Control.
Constellation..................... Constellation Energy Group.
Dominion.......................... Dominion Resources Services, Inc.
Duke.............................. Duke Energy Corporation.
Dynegy............................ Dynegy, Inc.
EEI............................... Edison Electric Institute.
ELCON............................. Electricity Consumers Resource
Council.
Entergy........................... Entergy Services, Inc.
EPSA.............................. Electric Power Supply Association.
ERCOT............................. Electric Reliability Council of
Texas, Inc.
Fertilizer Institute.............. Fertilizer Institute.
FirstEnergy....................... FirstEnergy Service Company.
Georgia Cities.................... City of Acworth.
City of Adel.
City of Blakely.
City of Cairo.
City of Calhoun.
City of Camilla.
City of College Park.
[[Page 16601]]
City of Commerce.
City of Doerun.
City of Douglas.
City of East Point.
City of Ellaville.
City of Fairburn.
City of Forsyth.
City of Fort Valley.
City of Grantville.
City of Hogansville.
City of Lafayette.
City of Lagrange.
City of Lawrenceville.
City of Mansfield.
City of Monticello.
City of Moultrie.
City of Norcross.
City of Oxford.
City of Palmetto.
City of Quitman.
City of Sanderville.
City of Sylvester.
City of Thomaston.
City of Thomasville.
City of Washington.
City of West Point.
Crisp County Power Commission.
City of Whigham.
Fitzgerald Water, Light and Bond
Commission.
Marietta Power and Water.
Georgia Operators................. Georgia System Operators Corp.
International Transmission........ International Transmission Company.
ISO/RTO Council................... ISO/RTO Council.
ISO-NE............................ ISO New England, Inc.
KCP&L............................. Kansas City Power and Light Company.
LPPC.............................. Large Public Power Council.
Manitoba.......................... Manitoba Hydro.
Marshall Municipal Utility Group Massachusetts Department of
Massachusetts DTE. Telecommunications and Energy.
MEAG Power........................ MEAG Power.
MidAmerican....................... MidAmerican Electric Operating
Companies.
Mid-Continent..................... Mid-Continent Systems Group.
MISO-PJM.......................... Midwest Independent Transmission
System Operator, Inc. and PJM
Interconnection, L.L.C.
MRO............................... Midwest Reliability Organization.
NARUC............................. National Association of Regulatory
Utility Commissioners.
National Grid..................... National Grid USA.
NCPA.............................. Northern California Power Agency.
NERC.............................. North American Electric Reliability
Corp.
New England Conference of Public New England Conference of Public
Utilities Commissioners*. Utilities Commissioners, Inc.
New York Commission............... New York State Public Service
Commission.
New York Public Power............. New York Association of Public
Power.
New York TOs...................... New York Transmission Owners.
Nevada Companies.................. Nevada Power Company and Sierra
Pacific Power Company.
Northeast Utilities............... Northeast Utilities Service Company.
Northern Indiana.................. Northern Indiana Public Service
Company.
Northwest Requirements Utilities.. Northwest Requirements Utilities.
NPCC.............................. Northeast Power Coordinating
Council: Cross-Border Regional
Entity, Inc.
NRC............................... United States Nuclear Regulatory
Commission.
NRECA............................. National Rural Electric Cooperative
Association.
NYSRC............................. New York State Reliability Council,
LLC.
NY Major Consumers................ Multiple Intervenors, an
unincorporated association of
approximately 55 large industrial,
commercial and institutional end-
use energy consumers with
facilities in New York.
Ontario IESO...................... Ontario Independent Electricity
System Operator.
Otter Tail........................ Otter Tail Power Company.
PG&E.............................. Pacific Gas and Electric Company.
Portland General.................. Portland General Electric Company.
Process Electricity Committee..... Process Gas Consumers Group
Electricity Committee.
Progress Energy................... Progress Energy, Inc.
ReliabilityFirst.................. ReliabilityFirst Corporation.
Reliant........................... Reliant Energy, Inc.
[[Page 16602]]
Santa Clara....................... City of Santa Clara, California.
SDG&E............................. San Diego Gas and Electric Company.
SERC.............................. SERC Reliability Corporation.
Six Cities........................ Cities of Anaheim, Azusa, Banning,
Colton, Pasadena, and Riverside,
California.
SMA............................... Steel Manufacturers Association.
Small Entities Forum.............. ReliabilityFirst Corporation Small
Entities Forum.
SoCal Edison...................... Southern California Edison Company.
South Carolina E&G................ South Carolina Electric and Gas
Company.
Southern.......................... Southern Company Services, Inc.
Southwest TDUs.................... Southwest Transmission Dependent
Utility Group.
STI Capital....................... STI Capital Company.
Tacoma............................ Tacoma Power.
TANC.............................. Transmission Agency of Northern
California.
TAPS.............................. Transmission Access Policy Study
Group.
TVA............................... Tennessee Valley Authority.
Utah Municipal Power.............. Utah Associated Municipal Power
Systems.
Valley Group...................... The Valley Group, Inc.
WECC.............................. Western Electricity Coordinating
Council.
WIRAB advice...................... Western Interconnection Regional
Advisory Body.
Wisconsin Electric................ Wisconsin Electric Power Company.
Xcel.............................. Xcel Energy Services.
------------------------------------------------------------------------
*Comments filed out-of-time.
Appendix C: Abbreviations in This Document
------------------------------------------------------------------------
------------------------------------------------------------------------
ACE..................................... Area Control Error.
AGC..................................... Automatic Generation Control.
ANSI.................................... American National Standards
Institute.
ATC..................................... Available Transfer Capability.
BCP..................................... Blackstart Capability Plan.
CBM..................................... Capacity Benefit Margin.
CPS..................................... Control Performance Standard.
DC...................................... Direct Current.
DCS..................................... Disturbance Control Standard.
DSM..................................... Demand-Side Management.
ERO..................................... Electric Reliability
Organization.
GWh..................................... Gigawatt hour.
IEEE.................................... Institute of Electrical and
Electronics Engineers.
IROL.................................... Interconnection Reliability
Operating Limits.
LSE..................................... Load-serving Entity.
MVAR.................................... Mega Volt Ampere Reactive.
MW...................................... Mega Watt.
ROW..................................... Right of Way.
SOL..................................... System Operating Limit.
SPS..................................... Special Protection System.
TIS..................................... Transmission Issues
Subcommittee.
TLR..................................... Transmission Loading Relief.
TRM..................................... Transmission Reliability
Margin.
TTC..................................... Total Transfer Capability.
UFLS.................................... Underfrequency Load Shedding.
UVLS.................................... Undervoltage Load Shedding.
------------------------------------------------------------------------
[FR Doc. E7-5284 Filed 4-3-07; 8:45 am]
BILLING CODE 6717-01-P