Mandatory Reliability Standards for the Bulk-Power System, 16416-16602 [E7-5284]
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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations
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.
Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule.
AGENCY:
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
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Paragraph
I. Introduction ...........................................................................................................................................................................................
A. Background ...................................................................................................................................................................................
1. EPAct 2005 and Order No. 672 .............................................................................................................................................
2. NERC Petition for Approval of Reliability Standards .........................................................................................................
3. Staff Preliminary Assessment and Commission NOPR .......................................................................................................
4. Notice of Proposed Rulemaking ............................................................................................................................................
II. Discussion ............................................................................................................................................................................................
A. Overview .......................................................................................................................................................................................
1. The Commission’s Underlying Approach to Review and Disposition of the Proposed Standards ..................................
2. Mandates of Section 215 of the FPA ....................................................................................................................................
3. Balancing the Need for Practicality with the Mandates of Section 215 and Order No. 672 ............................................
B. Discussion of the Commission’s New Regulations .....................................................................................................................
1. Applicability ..........................................................................................................................................................................
2. Mandatory Reliability Standards ..........................................................................................................................................
3. Availability of Reliability Standards ....................................................................................................................................
C. Applicability Issues ......................................................................................................................................................................
1. Bulk-Power System v. Bulk Electric System ........................................................................................................................
2. Applicability to Small Entities ..............................................................................................................................................
3. Definition of User of the Bulk-Power System ......................................................................................................................
4. Use of the NERC Functional Model ......................................................................................................................................
5. Regional Reliability Organizations ........................................................................................................................................
D. Mandatory Reliability Standards .................................................................................................................................................
1. Legal Standard for Approval of Reliability Standards ........................................................................................................
2. Commission Options When Acting on a Reliability Standard ...........................................................................................
3. Prioritizing Modifications to Reliability Standards .............................................................................................................
4. Trial Period ............................................................................................................................................................................
5. International Coordination ....................................................................................................................................................
E. Common Issues Pertaining to Reliability Standards ...................................................................................................................
1. Blackout Report Recommendation on Liability Limitations ...............................................................................................
2. Measures and Levels of Non-Compliance ............................................................................................................................
3. Ambiguities and Potential Multiple Interpretations ............................................................................................................
4. Technical Adequacy ..............................................................................................................................................................
5. Fill-in-the-Blank Standards ...................................................................................................................................................
F. Discussion of Each Individual Reliability Standard ...................................................................................................................
1. BAL: Resource and Demand Balancing ................................................................................................................................
2. CIP: Critical Infrastructure Protection ..................................................................................................................................
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TABLE OF CONTENTS—Continued
Paragraph
3. COM: Communications .........................................................................................................................................................
4. EOP: Emergency Preparedness and Operations ...................................................................................................................
5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities .................................................................
6. INT: Interchange Scheduling and Coordination ..................................................................................................................
7. IRO: Interconnection Reliability Operations and Coordination ..........................................................................................
8. MOD: Modeling, Data, and Analysis ....................................................................................................................................
9. PER: Personnel Performance, Training and Qualifications .................................................................................................
10. PRC: Protection and Control ...............................................................................................................................................
11. TOP: Transmission Operations ...........................................................................................................................................
12. TPL: Transmission Planning ...............................................................................................................................................
13. VAR: Voltage and Reactive Control ....................................................................................................................................
14. Glossary of Terms Used in Reliability Standards ..............................................................................................................
III. Information Collection Statement ......................................................................................................................................................
IV. Environmental Analysis .....................................................................................................................................................................
V. Regulatory Flexibility Act ...................................................................................................................................................................
VI. Document Availability .......................................................................................................................................................................
VII. Effective Date and Congressional Notification ................................................................................................................................
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
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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
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
https://www.ferc.gov/cust-protect/moi/blackout.asp.
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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.
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
4. On February 3, 2006, the
Commission issued Order No. 672,
implementing section 215 of the FPA.4
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).
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).
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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.
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
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).
7 Order No. 672 at P 262, 321–37.
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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
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
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
8. Pursuant to section 215(d)(2) of the
FPA and § 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 Interconnectionwide basis with respect to a proposed
Reliability Standard or a proposed
modification to a Reliability Standard to
be applicable within that
Interconnection. However, the
Commission will not defer to the ERO
or to such a Regional Entity with respect
8 Id.
at P 329.
at P 332.
10 Id. at P 337.
9 Id.
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to the effect of a proposed Reliability
Standard or proposed modification to a
Reliability Standard on competition.11
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
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.
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
11 18
CFR 39.5(c)(1), (3).
CFR 39.5(a).
13 18 CFR 39.5(e).
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, https://
www.nerc.com/filez/nerc_filings_ferc.html.
12 18
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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
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 NonCompliance, 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
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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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
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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.
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.
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
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).
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.
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.
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
19 NOPR
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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
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
25. Third, section 215 of the FPA
explains that the Bulk-Power System
broadly encompasses both the facilities
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 BulkPower 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).
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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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
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
23 16
U.S.C. 824o(a)(1).
U.S.C. 824o(a)(5).
25 16 U.S.C. 824o(a)(8).
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
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24 16
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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 Interconnectionwide basis for a Reliability Standard or
modification to a Reliability Standard to
be applicable on an Interconnectionwide 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
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
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
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).
28 16 U.S.C. 824o(d)(3).
29 16 U.S.C. 824o(j).
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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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.
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
31. We emphasize that we are not, at
this time, mandating a particular
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).
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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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.
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.
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B. Discussion of the Commission’s New
Regulations
1. Applicability
34. In the NOPR, the Commission
proposed to add § 40.1(a) to the
regulations. The Commission proposed
that § 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 § 39.2 of the
Commission’s regulations.
35. The Commission further proposed
to add § 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
36 FPT letter to Chairman Kelliher (submitted on
July 10, 2006) (placed in the record of this
proceeding).
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that particular Reliability Standard
applies.
which entities must comply with
particular Reliability Standards.
a. Comments
36. NERC agrees with the
Commission’s proposal to add the text
of § 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 § 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 § 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 § 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 BulkPower 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.
2. Mandatory Reliability Standards
40. The Commission proposed to add
§ 40.2(a) to the Commission’s
regulations. The proposed regulation
text would require that each applicable
user, owner and operator of the BulkPower System comply with
Commission-approved Reliability
Standards developed by the ERO, and
would provide that the Commissionapproved 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 § 40.2(b) to its regulations,
providing that a modification to a
Reliability Standard proposed to
become effective pursuant to § 39.5 shall
not be effective until approved by the
Commission.
b. Commission Determination
39. The Commission adopts the
NOPR’s proposal to add § 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
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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 § 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 § 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.’’
3. Availability of Reliability Standards
44. The Commission proposed to add
§ 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
37 NOPR
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NOPR’s proposal to add § 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.
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
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 BulkPower 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.
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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 Commissionapproved 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
1. Bulk-Power System v. Bulk Electric
System
50. The NOPR observed that, for
purposes of section 215, ‘‘Bulk-Power
System’’ means:
b. Commission Determination
48. For the reasons discussed in the
NOPR, the Commission adopts the
38 See
16 U.S.C. 824o(d)(2).
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C. Applicability Issues
(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
39 NOPR
at P 39–41.
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.
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.
40 See
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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.
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-bycase 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
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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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
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
44 NRECA, citing Morissette v. United States, 342
U.S. 246, 263 (1952).
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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 BulkPower 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 BulkPower 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
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16423
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.
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
45 See,
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e.g., NERC, TAPS and NRECA.
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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations
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.
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,
46 See
Rules of Procedure, § 500.
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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
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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 BulkPower 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
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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 caseby-case determinations to underlying
transmission systems operating at less
than 100 kV.
ycherry on PROD1PC64 with RULES2
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
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.’’
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Reliability Standards in the start-up
phase of a mandatory Reliability
Standard regime.48
76. However, we disagree with NERC,
APPA and NRECA that there is no
intentional distinction between BulkPower 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
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
48 See Section II.C.2., Applicability to Small
Entities, infra.
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.
51 See id. at P 64–65 & n.53–54.
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16425
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).
78. The Commission believes that the
above approach satisfies concerns raised
by NARUC and New York Commission
that the proposal to interpret BulkPower 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,
52 Id.
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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.
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
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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
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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.
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 BulkPower 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
ERO Rehearing Order at P 108.
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,
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.
88. California Cogeneration states
that, while focusing on entities that
have a material impact on the BulkPower 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.
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
53 See
54 NERC
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Attachment B; NERC’s February 6, 2007
supplemental filing.
55 See NOPR at P 1175–76.
56 18 CFR 292.601(c).
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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.
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 facilityby-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 BulkPower 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
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
57 California Cogenration at 6–7, citing California
Independent System Operator Corp., 96 FERC
¶ 63,015, at P 7, 24–25 (2001).
58 ERO Certification Order at P 689.
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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.
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
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.
60 See Supplemental Comments of TAPS
(February 13, 2007), APPA (February 14, 2007), and
NRECA (February 15, 2007).
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16427
compliance with particular Reliability
Standards.
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.
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
61 See
NERC Rules of Procedure, § 500.
at P 49.
62 NOPR
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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.
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.
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.
63 18
CFR 292.601(c).
resources deemed critical by the ERO
to Bulk-Power System reliability should be
included in the registry.
65 See ERO Certification Order at P679.
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.
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
64 Demand
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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
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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.
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
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.
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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
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 § 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.
a. Comments
111. APPA disagrees with a standardby-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
68 See NERC Supplemental Filing, Statement of
Compliance Registry Criteria (Revision 3), at 8–9.
69 NOPR at P 43.
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16429
‘‘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
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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 BulkPower 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.
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
70 NOPR
at P 46–48.
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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
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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.
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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
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
71 We note that NERC has available on its Web
site, https://www/nerc.com, the current version of
the Functional Model. We expect NERC to continue
to do so in the future.
72 NOPR at P 236.
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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
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 Commissionapproved 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
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.
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16431
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
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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 selfevident, 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
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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
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—
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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.
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
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.
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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.
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 § 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
75 NOPR
at P 54.
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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.
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16433
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
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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
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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
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:
as an interim measure * * * to direct the
ERO to use its authority pursuant to § 39.2(d)
of our regulations to require users, owners
and operators to provide to the regional
reliability organizations the information
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
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.
76 Order
No. 672 at P 654.
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.
78 NOPR at P 57 (footnotes omitted).
77 EOP–007,
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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
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
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
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
79 See
ERO Certification Order at P 281.
No. 672 at P 262, 321–37.
81 NOPR at P 74.
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.
80 Order
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Reliability Standard satisfies the
statutory requirements.
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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
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presumption that a proposed Reliability
Standard developed through an ANSIcertified 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.
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.
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
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
83 Order
No. 672 at P 338.
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.’’)
85 NOPR at P 78–82.
84 Id.
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16435
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.
174. Many commenters request that
the Commission require that changes to
any Reliability Standard be made
through NERC’s Reliability Standard
86 See, e.g., NERC, Entergy, EEI, APPA, National
Grid, NRECA, TAPS, ISO–NE and Duke.
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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.
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
87 See, e.g., NERC, EEI, ELCON, CEA, NYSRC,
TVA, LPPC, NPCC, Ontario IESO, Constellation,
Progress and Dynegy.
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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 yetto-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
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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
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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.
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
88 See
NOPR at P 79–80.
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.’’).
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.
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89 16
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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.
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 threeyear review cycle contemplated by
91 16
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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.
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
92 See discussion below regarding the Trial
Period, section II.D.4.
U.S.C. 824o(d)(5).
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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
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
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.
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
93 See
18 CFR 39.5(g).
at P 85–87.
95 Id. at Appendix D (High Priority List).
94 NOPR
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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.
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.
96 Some projects relate to new Reliability
Standards that are not before the Commission in the
instant rulemaking.
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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.
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 NonCompliance 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 Non97 NOPR
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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 NonCompliance 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,
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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.
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,
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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the NOPR did not propose a trial
period.99
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.
211. NPCC essentially agrees with the
Commission that there should be no
trial period, but if the definition of BulkPower System is substantially altered to
99 Id.
at P 92–93.
e.g., EEI, APPA, TAPS, EPSA, CAISO,
Bonneville, California PUC, Cleveland, Otter Tail,
Northwest Requirements Utilities, TVA and SMA.
100 See,
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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 wellunderstood 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
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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
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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
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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.
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.
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
101 NOPR
102 Id.
at P 92.
at P 93.
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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 BulkPower 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
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appropriate penalty within the range of
applicable penalties.103
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
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
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.
103 ERO
Certification Order at P 451.
Order No. 672 at P 400.
105 ERO Certification Order at P 286.
106 Compliance Filing of the North American
Electric Reliability Council and the North American
Electric Reliability Corporation Addressing NonGovernance Issues, Appendix 3C, Docket No.
RR06–1–000 (October 18, 2006).
104 See
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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 NERCproposed 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 continentwide Reliability Standards.
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
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 BulkPower 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
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
a. Comments
236. EEI states that the Commission
should adopt OATT liability limitations
to implement Blackout Report
109 Order
107 January
2007 Compliance Order at P 44.
108 Id.
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No. 672 at P 296.
at P 99–100.
111 Blackout Report at 147
110 NOPR
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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
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
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).
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
https://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,
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has offered no arguments that
demonstrate that an OATT limit on
liability is warranted.
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2. Measures and Levels of NonCompliance
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.
239. In the NOPR, while the
Commission recognized the importance
of having Measures and Levels of NonCompliance 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 NonCompliance.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.
240. The NOPR explained that the
common format of NERC’s proposed
225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New
York v. FERC, 535 U.S. 1 (2002).
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 noncompliance with a Reliability Standard. The Levels
of Non-Compliance range from Level 1 to Level 4,
with Level 4 being the most severe.
120 NOPR at P 105–07.
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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 NonCompliance. 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.
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243. NYSRC states that, in NERC’s
rush to file with the Commission the 20
revised Reliability Standards with new
Measures and Levels of NonCompliance, 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.
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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 NonCompliance should be based on
objective criteria and that a ‘‘level 4’’
violation should reflect a commensurate
level of severity in its impact on BulkPower 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 NonCompliance 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
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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 NonCompliance 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 NonCompliance. A simple penalty structure
would reduce enforcement ambiguities,
increase uniformity and promote greater
clarity. FirstEnergy states that, without
Measures and Levels of NonCompliance, a Reliability Standard
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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
252. Progress and Xcel state that the
Commission should clarify that the
Measures and Levels of NonCompliance 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
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
121 FirstEnergy at 10–11, citing NOPR at P 16; see
also Order No. 672 at P 262, 321–37.
122 NOPR
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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 NonCompliance. Where a Reliability
Standard can be improved by providing
missing Measures or Levels of NonCompliance 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
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 NonCompliance 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
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 NonCompliance 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.
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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
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.
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
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.
126 NOPR at P 107.
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16445
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.
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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.
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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
127 NOPR
at P 110–12.
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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
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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 BulkPower 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
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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.
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
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.
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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-bystandard 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
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16447
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, BulkPower 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 NonCompliance 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
129 January
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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.
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
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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-bystandard 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.
130 NOPR
at P 115.
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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 continentwide 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.
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 fillin-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-inthe-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
131 January
2007 Compliance Order at P 18.
at P 116.
133 Id. at P 121, citing Order No. 672 at P 292;
ERO Certification Order at P 274.
132 NOPR
PO 00000
Frm 00034
Fmt 4701
Sfmt 4700
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.
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-theblank standards) as pending at the
Commission until further information is
provided, and to require that BulkPower 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 § 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
134 NOPR
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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-theblank 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.
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
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.
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forma OATT, effective when the
Reliability Standards become mandatory
in June 2007, because a reliabilityrelated 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 fillin-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-theblank standards should continue on a
voluntary basis, and the Commission
considers compliance with such
Reliability Standards to be a matter of
good utility practice.
298. As noted above, some
commenters such as TAPS urge the
Commission to view most regional
136 NOPR
PO 00000
at P 123.
Frm 00035
Fmt 4701
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.
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
137 Id.
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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
138 Policy
Statement on Matters Related to Bulk
Power System Reliability, 107 FERC ¶ 61,052 at P
23–26 (2004) (Reliability Policy Statement).
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approved by the Commission under
section 215.
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
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
139 NOPR
PO 00000
at P 136.
Frm 00036
Fmt 4701
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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.
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
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
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.
141 Id. at P 143.
142 Order No. 672 at P 290.
143 Id. at P 291.
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preferential and in the public
interest.144
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.
i. General Comments
c. Disturbance Control Performance
(BAL–002–0)
ii. Commission Determination
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.
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
§ 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.
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144 Id.
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.
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.
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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.
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 NonCompliance 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.
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
149 NERC
PO 00000
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16451
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.
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 demandside 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
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.
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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.
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
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.
NERC, ISO–NE, APPA and SDG&E.
comments jointly with respect to
IRO–006–3 only.
(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 objectivebased 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
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
151 See
152 MISO–PJM
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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.
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
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
155 Id. (‘‘We leave it to the ERO to develop
proposed Reliability Standards that appropriately
balance reliability principles and implementation
features.’’)
156 See https://www.electricitycommission.govt.nz/
pdfs/rulesandregs/rules/rulespdf/Part-C-sched-C51Dec06.pdf.
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.
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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,’’ ‘‘nonspinning,’’ ‘‘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.
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
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.
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 BulkPower 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 continentwide 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
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
161 NOPR
158 See
APPA, International Transmission, MISO–
PJM, LPPC and California PUC.
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160 Although Frequency Response and Bias are
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at P 153.
NERC, APPA, Xcel, MRO, ISO–NE, EEI
and Nevada Companies.
162 See
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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.
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
163 See
NOPR at n.116.
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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
354. In the NOPR, the Commission
identified two concerns in the
164 Id.
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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.
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
vi. Summary of Commission
Determination
357. The Commission approves
Reliability Standard BAL–002–0 as
165 NERC Comments on the Staff Preliminary
Assessment at 41.
166 NOPR at P 153.
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.
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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.
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 § 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 NonCompliance and (2) modifies Measure
M1 to include yearly surveys of
frequency response.171
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
i. Comments
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360. Several commenters address the
Commission’s proposal to direct the
168 This could be accomplished by modifying
Requirement R2 or developing a new Reliability
Standard.
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.
172 Id. at P 175.
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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 overcompensated 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
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16455
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.
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 counterproductive by making procedural errors
more likely, which could harm
reliability. Northern Indiana suggests
that the approach suggested in the
NOPR would require frequency
173 See
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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
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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 BulkPower 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
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 overcompensated 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
174 Order
No. 672 at P 324.
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.
175 As
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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.
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.
374. As the Commission noted in the
NOPR and in our response to
FirstEnergy, Requirement R2 of this
176 See Underfrequency Load Shedding 2006
Assessment and Review by ERCOT Dynamics
Working Group, available at https://www.ercot.com/
meetings/ros/keydocs/2007/0111/
10a._DWG_2006_UFLS_Assessment_12-18-06.doc.
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.
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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.
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.
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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
178 Cohn, Nathan, Control of Generation and
Power Flow on Interconnected Systems, (John Wiley
and Sons 1966).
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.
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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 § 39.5(f) of our regulations, the
Commission proposed to direct that
NERC submit a modification to BAL–
004–0 that includes Levels of NonCompliance and additional Measures.180
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.
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 WECCtype 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.
180 NOPR
at P 184.
https://www.wecc.biz/documents/library/
procedures/Time_Error_ Procedure_10-04-02.pdf.
182 See https://www.nerc.com/~filez/inadv.html
(regarding inadvertent interchange data) and https://
www.nerc.com/~filez/timerror.html (regarding time
error correction).
183 See Xcel, Northern Indiana, ISO–NE, LPPC
and MISO–PJM.
181 See
PO 00000
Frm 00043
Fmt 4701
Sfmt 4700
16457
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 § 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 NonCompliance 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
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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.
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
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.
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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
§ 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
PO 00000
Fmt 4701
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.
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.
187 See APPA, EEI, International Transmission,
MISO–PJM, MidAmerican and LPPC.
at P 197.
Frm 00044
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.
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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
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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.
16459
ii. Title Change and Inclusion of DSM.
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.
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.
(a) Comments
(b) Commission Determination
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.
402. Constellation agrees with the
Commission that DSM and direct
control load management should be
included as viable options for regulating
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
188 EEI,
TVA, International Transmission,
Multiple Interveners, MISO–PJM, South Carolina
E&G and Wisconsin Electric.
PO 00000
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Fmt 4701
Sfmt 4700
189 Since the Commission used the term
‘‘contingency reserves’’ inappropriately in this
section, we assume that Constellation intended this
to be regulating reserves.
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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
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(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
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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 nonfirm 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.
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
190 NOPR
PO 00000
at P 194.
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Fmt 4701
Sfmt 4700
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
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
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
191 See California Cogeneration at 6, citing
California Independent System Operator Corp.,
Opinion No. 464, 104 FERC ¶ 61,196 (2003).
192 NOPR at n.134.
193 See R. L. Vice, Frequency Issues 2005,
available at: https://www.wecc.biz/documents/
library/RITF/Frequency_Issues_2005_rev_0.pdf.
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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.
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
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 § 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
§ 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
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 NonCompliance for large accumulations, it
must insure that no ‘‘double penalties’’
are imposed.
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
197 Xcel,
Applicability Issues: Bulk-Power Ststem v.
Bulk Electric System and Applicability to Small
Entities, supra sections II.C.1–2.
195 See Common Issues Pertaining to Reliability
Standards: Measures and Levels of NonCompliance, supra section II.E.2.
MRO, MidAmerican and MISO–PJM.
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.
194 See
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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
(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 NonCompliance. 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
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
199 OATT
Reform NOPR at P 208.
at P 206.
201 See BAL–006–1 (Inadvertent Interchange,
Purpose Statement).
200 NOPR
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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
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.
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.
ii. Whether the Accumulation of Large
Amounts of Inadvertent Imbalances Is a
Concern and Potential Options
iii. Summary of Commission
Determinations
(a) Comments
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 § 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.
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
202 See
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(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.
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,
203 NOPR
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and NERC approved, the same regional
difference for.204
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.
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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.
204 BAL–006–1, filed on August 28, 2006, would
extend the regional difference to SPP.
205 Order No. 672 at P 291.
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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
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
§ 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
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.
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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 BulkPower System. California Cogeneration
suggests that CIP–001–1 be revised to:
(1) Exclude generator output used onsite 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
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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.
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-inthe-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
208 See, e.g., APPA, FirstEnergy, SoCal Edison,
Six Cities and TAPS.
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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
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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
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(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
ycherry on PROD1PC64 with RULES2
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.
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
209 See
NOPR at P 224.
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. * * *’’
210 Id.
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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
211 NOPR
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at P 228.
Frm 00051
Fmt 4701
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.
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
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’’
212 Id.
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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
213 Id.
at n.142.
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events occurring outside staffed hours at
small entities.
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
§ 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
PO 00000
Frm 00052
Fmt 4701
Sfmt 4700
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.
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.
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 NonCompliance; (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.
214 See Applicability Issues: Use of the NERC
Functional Model, supra section II.C.4.
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.
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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.
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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
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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 BulkPower 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 ‘‘overstepping 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.
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
216 COM–001–1 Requirement R1.4 states: ‘‘Where
applicable, these [telecommunications] facilities
shall be redundant and diversely routed.’’
PO 00000
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Fmt 4701
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16467
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
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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.
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
217 See
Applicability Issues: Applicability to
Small Entities, supra section II.C.2.
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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 BulkPower 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
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Fmt 4701
Sfmt 4700
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 BulkPower 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.
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
218 See, e.g., EEI, International Transmission,
ISO–NE, Process Electricity Committee and SoCal
Edison.
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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
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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.
(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 costeffective solutions for compliance with
the Reliability Standard. However, the
Commission finds that certain
modifications to COM–001–1 are
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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16469
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 NonCompliance
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
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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
§ 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.
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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
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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communication paths of any condition
that could threaten the reliability of
their areas or when firm load shedding
is anticipated.
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
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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 NonCompliance
(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.
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
221 See Common Issues Pertaining to Reliability
Standards: Measures and Levels of NonCompliance, supra section II.E.2.
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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.
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
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.
224 The Requirement R13 of IRO–005–1 provides
that ‘‘[e]ach reliability coordinator shall ensure that
Transmission Operators, Balancing
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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.
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 widearea impacts that would adversely
impact Reliable Operation of the BulkPower System. Therefore, we adopt the
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.’’
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 widearea 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.
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16471
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.
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
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 * * *.’’
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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
227 Blackout
228 Id.
Report at 107.
at 141.
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responds to the Blackout Report
Recommendation.
(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
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.
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
229 NOPR
at P 255.
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.’’
230 EOP–001–0,
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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 continentwide basis. This will eliminate possible
ambiguities in communications during
normal, alert and emergency conditions.
This is important because the BulkPower 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
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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.
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(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 § 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
231 This Requirement could, for example, be
included in COM–002–2 or in an operating
Reliability Standard.
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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.
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
§ 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
PO 00000
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Fmt 4701
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16473
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
232 NOPR
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operating emergencies for their specific
areas of responsibility, unlike reliability
coordinators, they do not have widearea views.
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
ycherry on PROD1PC64 with RULES2
(a) Comments
550. NERC comments that the
proposed directive to clarify the 30minute 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
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18:02 Apr 03, 2007
Jkt 211001
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 30minute 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.
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
233 Id.
at P 273.
Frm 00060
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
235 Id.
234 Id.
PO 00000
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.
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
at P 995.
236 Id.
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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.
ycherry on PROD1PC64 with RULES2
(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
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
237 Id.
238 Id.
at P 275.
at P 276.
VerDate Aug<31>2005
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.
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
239 Id.
18:02 Apr 03, 2007
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16475
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 § 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 30minute 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
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.
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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.
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 § 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.
ycherry on PROD1PC64 with RULES2
(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.
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18:02 Apr 03, 2007
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ii. Demand-Side Management
iii. Warning regarding TLR procedure
(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.
(a) Comments
(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.
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.’’
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Frm 00062
Fmt 4701
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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
(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
243 ISO–NE also notes that in the first line of
Requirement R7 the reference to ‘‘R7’’ should be to
‘‘R6.’’
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ycherry on PROD1PC64 with RULES2
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.
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
244 See, e.g., APPA, EEI, Entergy and
MidAmerican.
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20:19 Apr 03, 2007
Jkt 211001
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-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-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 § 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
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.
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Fmt 4701
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16477
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.
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 § 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 NonCompliance.
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.
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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.
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(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
246
247 See Xcel, ISO–NE, TVA, International
Transmission and MISO.
NOPR at P 294.
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uncontrolled failure of system elements
or cascading outages is increased.
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.
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
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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,
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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-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-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
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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.
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 § 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.
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 § 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
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
https://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.’’)
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.
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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.
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611. APPA states that NERC’s
November 15, 2006 revision partially
fulfills the proposed modification to
include Measures and Levels of NonCompliance. 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 BulkPower 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.
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
251 NOPR
at P 304.
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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 § 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
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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
§ 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 NonCompliance elements refer only to
transmission operators.
623. ISO-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-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 simulationbased training on emergencies and
restoration and it is unclear what is
meant by conducting training to prepare
operators for unforeseen events.
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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 companyspecific 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
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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.
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 § 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
252 See
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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 § 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.
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 § 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 NonCompliance.
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 NonCompliance 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.
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.
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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
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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
§ 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
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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.
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
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
254 See
255 See
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FirstEnergy at 35.
NOPR at P 328.
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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.
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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
§ 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.
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(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 riskbased 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
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16483
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.’’
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
257 NOPR
258 See
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at P 329.
Id. at P 336.
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should correspond to the time it would
take to replace the primary control
center.
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
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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 BulkPower 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 centrallylocated 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 costeffective, especially considering the
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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.
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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 § 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.
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 rightsof-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.
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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.
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,
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16485
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
§ 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
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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 enduser 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.
689. FirstEnergy asks the Commission
to state that complying with MISO’s and
PJM’s interconnection agreements and/
259 FAC–002–0.
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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.
(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
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).
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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 enduser 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.
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 § 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.
261 NOPR
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Further, the Commission also directs the
ERO to consider the above commenters’
concerns through the Reliability
Standards development process.
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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
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
§ 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.
262 FAC–003–1
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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 impactbased 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 BulkPower 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.
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.
263 An IROL-related facility is a facility whose
outage would result in an Interconnection
Reliability Operating Limit (IROL) violation.
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16487
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 BulkPower 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 BulkPower System. NERC notes that the
current applicability of the Reliability
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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
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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 lowervoltage 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
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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
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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.
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
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.
(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
(a) Comments
724. APPA believes that a case-bycase approach may have to be
employed, since Forest Service lands
are located all across the country and
have different regional characteristics.
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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.
264 Utility Vegetation Management and Bulk
Electric Reliability Report at 10–11, available at
https://www.ferc.gov/industries/electric/indus-act/
reliability/2004.asp (Vegetation Management
Report).
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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.
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
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.
267 Forest Service, Bureau of Land Management,
Fish & Wildlife Service, National Park Service, and
U.S. Environmental Protection Agency.
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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.
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 rightof-way.
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(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
268 The Vegetation MOU is available at https://
www.eei.org/industry_issues/environment/land/
vegetation_management/EEI_MOU_FINAL_5-2506.pdf.
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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 rightof-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-bycase 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
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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
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 caseby-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
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.
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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 rightsof-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.
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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 caseby-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.
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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
§ 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
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16491
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
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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
272 NOPR
at P 404.
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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.
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
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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
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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
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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
273 An element is made up of one or more
components.
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16493
impediment to service to major cities or
load pockets.
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 BulkPower 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.
760. In response to Dominion’s
comments, if the PJM Regional
Transmission Expansion Planning
process meets the criteria, there is no
274 16
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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
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(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.
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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
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Fmt 4701
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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.
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.
275 Blackout
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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.
ycherry on PROD1PC64 with RULES2
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 intraregional 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.
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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.
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.
i. Methodology
ii. Transparency and Confidentiality
(a) Comments
(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.
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
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
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(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
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criteria used for other users of the BulkPower 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.
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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
§ 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
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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
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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
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
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 § 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.
276 See
supra P 780.
No. 890 at P 196.
277 Order
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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.
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.
ycherry on PROD1PC64 with RULES2
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,
278 The NERC glossary defines ‘‘interchange’’ as
‘‘Energy transfers that cross Balancing Authority
boundaries.’’ NERC Glossary at 9.
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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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
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16497
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.
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
§ 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
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 eTagging requirements as part of its
280 Currently, the reliability analysis service used
by NERC is the Interchange Distribution Calculator.
281 This Requirement was included in INT–001–
0 as Requirement R1.2.
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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 NonCompliance 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.
ycherry on PROD1PC64 with RULES2
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
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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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.’’
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
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
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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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-topoint 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
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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
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
284 The Requirement was included in INT–001–0
as Requirement R1.2.
285 To date, the Commission has not received the
requested information.
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consider any regional differences
contained in a proposed WECC tagging
requirement for dynamic schedules
when submitted by NERC for
Commission review.
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.
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
286 Order
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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 Commissionapproved, 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.
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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 NonCompliance.
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.
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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.
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 multicontrol area energy market. The NOPR
stated that the regional difference is
appropriate because it is more stringent
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.
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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 Commissionapproved 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
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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 BulkPower System that is required to comply
with mandatory Reliability Standards.
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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.
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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 widearea 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
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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
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16501
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
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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
288 NOPR
at P 219.
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notification time prior to actual
transactions, this proactive approach
should promote system reliability.
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 widearea 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 widearea and local area reliability
viewpoints respectively and, where
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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,
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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.
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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
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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 reliabilityrelated 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 NonCompliance, should be edited to state
that ‘‘[t]here shall be a level four non-
PO 00000
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16503
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,
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Reliability Standards development
process.
ii. Commission Determination
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consistent with Commission
expectations.
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 widearea 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.
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 30minute 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
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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 NonCompliance.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 purchasingselling 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 purchasingselling entities ‘‘shall comply with
Reliability Coordinator directives unless
such actions would violate safety,
equipment, or regulatory or statutory
requirements.’’
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 § 39.5(f) of our
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 * * *.’’
290 IRO–001–1 supercedes the Version 0
Reliability Standard. In this Final Rule, we review
the November version, IRO–001–1.
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Fmt 4701
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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.
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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.
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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
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 NonCompliance 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
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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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
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 § 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
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.
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16505
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 NonCompliance, 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
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
294 See
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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.
c. Reliability Coordination—Wide Area
View (IRO–003–2)
910. The purpose of IRO–003–2 is for
a reliability coordinator to have a widearea 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
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 § 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.
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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
295 NOPR
at P 511.
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.
296 In
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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.
915. Further, pursuant to section
215(d)(5) of the FPA and § 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
§ 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 Non297 See
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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 dayahead 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
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
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-themeter information, whether on generation or load.’’
299 See NOPR at P 529.
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addition, the Commission directs the
ERO to develop modifications to the
Reliability Standard, as discussed
below.
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.
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 reaffirmation 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 dayahead 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
300 IRO–004–1 Purpose Statement states in part
‘‘Plans must be developed to alleviate SOL and
IROL violations.’’
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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 30minute 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
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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 NonCompliance 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
§ 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
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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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
302 IRO–005–1 Requirement R14 states ‘‘Each
Reliability Coordinator shall make known to
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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
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.’’
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
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provide guidance on the frequency,
duration and magnitude of IROL
violations, their causes and whether
these IROL violations occur during
normal or contingency conditions.
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.
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.
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Further, because IRO–005–1 has no
Measures or Levels of Non-Compliance,
pursuant to section 215(d)(5) of the FPA
and § 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 NonCompliance 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.
TLR procedure is an inappropriate and
ineffective tool to mitigate IROL
violations; (2) identifies in a
Requirement the available alternatives
to use of the TLR procedure to mitigate
an IROL violation and (3) includes
Measures and Levels of NonCompliance that address each
Requirement. In addition, the
Commission proposed to approve the
WECC and ERCOT load relief
procedures as superior to the national
standard.
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.
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
§ 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
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 NonCompliance 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.
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.
ii. Commission Determination
961. The Commission approves IRO–
006–3 as mandatory and enforceable. In
addition, we direct the ERO to develop
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16509
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.
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
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.’’
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consistency with the standard form of
the Reliability Standards including
Requirements, Measures and Levels of
Non-Compliance.308
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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.
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 nonmarket 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.
308 See
NOPR at P 564–65.
at P 568.
309 NOPR
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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 nondiscriminatory 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-toload 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
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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 giveand-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. MidContinent 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
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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
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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 counterflow 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
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16511
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 MidContinent 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-toload 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
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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-toload 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 areabased 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.
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(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 nonmarket 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
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.
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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-nonmarket 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
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 nonmarket 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.
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 PJMMidwest 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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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 12month 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 nonmarket 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 nonmarket entities to report their generatorto-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-bycase basis or, as appropriate, in the
proceeding on RTO Border Utility
Issues.315
315 See RTO Border Utility Issues, Notice of
Technical Conference on Seams Issues for RTOs
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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 agreedupon 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.
and ISOs in the Eastern Interconnections (Docket
No. AD06–9–000) (issued Jan. 25, 2007).
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16513
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
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 NonCompliance 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
316 IRO–016–1 Level of Non-Compliance 2.1
states: ‘‘For potential, actual or expected events
which required Reliability Coordinator-toReliability Coordinator coordination, the Reliability
Coordinator did coordinate, but did not have
evidence that it coordinated with other Reliability
Coordinators.’’
317 MOD–001–0 through MOD–009–0.
318 MOD–010–0 through MOD–015–0.
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covers actual and forecast demand
data.319 The fourth category covers
verification of generator real and
reactive power capability.320
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.
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-inthe-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-theblank 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
319 MOD–016–0
through MOD–021–0.
through MOD–025–1.
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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320 MOD–024–1
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concern with the Commission’s
proposal not to act on the 13 fill-in-theblank 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.
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
322 See Common Issues Pertaining to Reliability
Standards: Fill-in-the-Blank Standards, supra
section II.E.5.
323 OATT Reform Final Rule, Order No. 890,
issued February 15, 2007.
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completes work on the MOD Reliability
Standards.
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
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
324 FPA
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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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(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
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://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.
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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
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16515
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-
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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 BulkPower 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.
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.
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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
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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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
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
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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.
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
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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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-topoint 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 shortterm ATC calculation, all reserved but
unused transfer capability (nonscheduled) must be released as non-firm
ATC.
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 industrywide 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.
332 TRM also includes such things as loop flow
and parallel path flow.
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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.
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.
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.
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16517
(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.
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
334 NOPR
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at P 169.
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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 (peakand 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
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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 shortterm 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 preschedule) and (3) planning horizon
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(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 BulkElectric 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
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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.
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 steadystate, dynamic stability or voltage
stability. We are certain that consistent
Reliability Standards and we did not have sufficient
time to allow appropriate review and comment.
336 For example, WECC has a documented open
process for establishing TTC for the Western
Interconnection.
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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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.
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 BulkPower 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).
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
339 NOPR
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16519
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 Commissionapproved 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,
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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-theblank 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.
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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
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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-theblank 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
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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.
1069. In the NOPR, the Commission
identified MOD–004–0 as a fill-in-theblank 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
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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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.
ycherry on PROD1PC64 with RULES2
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
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
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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16521
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.
1075. EEI agrees with the
Commission’s concern about doublecounting 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
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
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).
343 Documented by NERC’s April 14, 2005 LongTerm 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.
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Fmt 4701
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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.
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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
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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
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Fmt 4701
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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-theblank 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,
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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
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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.
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.
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
346 Id.
345 NOPR
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at P 647–48.
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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 doublecounting. 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.
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 nonfirm 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.
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.
349 TOP–002–2.
348 See
NERC Glossary at 2.
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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
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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-theblank 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
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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
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16525
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 MAPPapproved 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
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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
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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-theblank 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
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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
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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,
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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.
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-themeter 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
351 MidAmerican further cautions that other
contingencies exist that must be studied under stilldifferent 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.
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16527
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
352 NOPR
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concerns and to develop a consensus
standard using its Reliability Standard
development process.
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 § 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.
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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, commerciallysensitive 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
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Fmt 4701
Sfmt 4700
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.
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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-theblank 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 fillin-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.
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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.
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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.
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16529
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 fillin-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
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used in a ‘‘cook-book’’ manner to reach
the wrong conclusions.353
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
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.
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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 § 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
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Fmt 4701
Sfmt 4700
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 ‘‘cookbook,’’ 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
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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-theblank standard that requires each
regional reliability organization within
an Interconnection to develop
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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.
i. Comments
1190. APPA agrees with the
Commission that MOD–013–1 is a fillin-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
354 Requirement R1.1.1 allows for the use of
estimated or typical manufacturer’s data on pre1990 units to model dynamic behavior when unitspecific data is unavailable.
355 EEI, LPPC, MidAmerican, Small Entities
Forum and TVA.
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technical review and approval of any
estimates at the regional level.
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 unitspecific 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-bycase 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 upto-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
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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 cutoff 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 unitspecific 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 unitspecific 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
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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 steadystate 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-theblank standard that requires the regional
reliability organizations within an
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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.
i. Comments
1205. APPA agrees with the
Commission that MOD–014–0, a fill-inthe-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.
356 FERC Form 715 is available at https://
www.ferc.gov/docs-filing/eforms.asp#715.
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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.
1212. Further, the maximum
discrepancy between the model results
357 Recommendation Number 24 of the Blackout
Report at 160.
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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 § 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
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16533
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-theblank 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.
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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 § 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
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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.
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
358 TPL–005–0, TPL–006–0, MOD–011–0, MOD–
013–0, MOD–014–0 and MOD–015–0.
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argue that NERC, as the standardssetting 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
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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
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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
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16535
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
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
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.
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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
360 Order
No. 672 at P 329.
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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.
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.
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
361 See Brattle Group Report on PJM Load
Forecast Model, available at https://www.pjm.com/
planning/res-adequacy/load-forecast.html.
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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.
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,
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 https://www.eia.doe.gov/cneaf/
electricity/page/forms.html.
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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.
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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
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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.
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
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.
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16537
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 10year 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 percentagebased 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
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percentage deviations as compliance
measures can produce discriminatory
results, and has applied MW minimums
to minimize the discrimination that
would otherwise result.
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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
§ 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.
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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
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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 regionspecific 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.
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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
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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
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16539
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
§ 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
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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-theblank 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
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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
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
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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.
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
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.
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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
§ 39.2(d) of our regulations to require
users, owners and operators to provide
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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-theblank 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,
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16541
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,
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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
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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
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operator training are discussed in PER–
002–0.365
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
365 See Applicability Issues: Use of the NERC
Functional Model, supra section II.C.4.
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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.
ycherry on PROD1PC64 with RULES2
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
(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
366 NOPR
367 Id.
at P 236–37.
at P 237, 779.
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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 NERCcertified operators and that such
employees are subject to round-theclock 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 BulkPower 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
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16543
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
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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 centrallylocated 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 centrallylocated 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
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 NERCcertified 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
368 The Commission expects the entity registered
as the transmission operator to ensure that these
personnel are competent for the tasks that they
perform.
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independently to carry out tasks that
require real-time operation of the BulkPower 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.
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
(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.
369 See
370 Id.
PO 00000
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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 BulkPower 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
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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 NERCcertified. 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.
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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
371 NOPR
PO 00000
at P 771.
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sufficient training to take appropriate
action to ensure reliability of the BulkPower System. Thus, we direct the ERO
to develop a modification to make PER–
002–0 applicable to generator operators.
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
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
372 The Commission expects the entity registered
as the generator operator to ensure that plant
operators are competent for the tasks that they
perform.
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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.
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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
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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.
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
373 NOPR
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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.
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 overlyprescriptive 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.
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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.
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
(a) Comments
1378. Xcel does not agree that
performance metrics should be included
(a) Comments
1382. ISO–NE states that the use of
SAT methodology should not be
374 Id.
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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
(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
376 Id.
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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 firsthand 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
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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 fullscale 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 fullscale 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
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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 § 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.
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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.
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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
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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
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16549
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 BulkPower 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 BulkPower 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
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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 NERCcertified. 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
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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 § 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 BulkPower System for which they are
responsible.
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
§ 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
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.
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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 NonCompliance 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 NonCompliance 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
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addition, pursuant to section 215(d)(5)
of the FPA and § 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.
informed immediately upon the
detection of failures in relays or
protection system elements on the BulkPower 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.
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.
i. Comments
1422. While Constellation supports
the Commission’s proposed directives
because they represent additional steps
to achieving reliability of the BulkPower 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 NonCompliance, 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 nonexistent 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
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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.
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
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.
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16551
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 30minute 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
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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
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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.
(a) Whether Relay or Equipment
Failures Reduce System Reliability and,
if So, in What Circumstances?
1436. Protection systems on BulkPower 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
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,
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.’’
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.
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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 reconfiguration, 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 BulkPower 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
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‘‘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 NonCompliance incorrectly reference nonexistent 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
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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 BulkPower 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-theblank 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.
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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.
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
381 Order
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systems and to develop and document
corrective actions.
1459. In the NOPR, the Commission
identified PRC–003–1 as a fill-in-theblank 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.
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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.
382 Id.
at P 292.
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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.
1470. We direct the ERO to consider
ISO–NE’s suggestion that LSEs and
transmission operators should be
included in the applicability section, in
383 NOPR
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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.
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
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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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.
1478. In the NOPR, the Commission
identified PRC–006–0 as a fill-in-theblank 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
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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 BulkPower System, is one of the safety nets
that safeguards the system from
385 Underfrequency
load shedding.
load shedding.
387 NOPR at P 367.
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.
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.
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.
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
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
386 Undervoltage
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388 NOPR
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h. Underfrequency Load Shedding
Equipment Maintenance Programs
(PRC–008–0)
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-inthe-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.
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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.
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
389 See
PRC–008–0, Requirement R1.
at P 56–57.
390 NOPR
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impact on the reliability of the BulkPower 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-inthe-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
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
391 NOPR
392 NOPR
PO 00000
at P 877–80.
at P 56–57.
Frm 00142
Fmt 4701
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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.
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
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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.
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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
1508. Regarding FirstEnergy’s
question of whether universal
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.
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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.
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.
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
394 NOPR
395 Id.
PO 00000
P 883.
P 891–92.
Frm 00143
Fmt 4701
Sfmt 4700
16557
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 BulkPower 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.
In the NOPR, the Commission
identified PRC–012–0 as a fill-in-theblank standard. The NOPR stated that
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.
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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-theblank 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
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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
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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-theblank 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
PO 00000
Frm 00144
Fmt 4701
Sfmt 4700
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.
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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.
ycherry on PROD1PC64 with RULES2
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
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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.
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Frm 00145
Fmt 4701
Sfmt 4700
16559
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-theblank 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
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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-theblank 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 fillin-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.
ycherry on PROD1PC64 with RULES2
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
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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
PO 00000
Frm 00146
Fmt 4701
Sfmt 4700
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 NonCompliance. On November 15, 2006,
NERC submitted revisions to the
Reliability Standard to include
Measures and Levels of NonCompliance.397
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.
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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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 noncompliant 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
398 California Cogeneration notes that the
curtailment of QFs in an emergency is allowed by
18 CFR 292.307.
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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 NonCompliance 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 § 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
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 BulkPower 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 BulkPower 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
399 Santa Clara makes a similar argument
reagarding Requirement R3 of TOP–008–1.
400 See 18 CFR 39.6 (Conflict of a Reliability
Standard with a Commission Order).
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.
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
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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.
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
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* * *.’’
402 Requirement R4 states: ‘‘Each Distribution
Provider * * * shall comply with all reliability
directives * * * unless such actions would violate
safety, equipment, regulatory or statutory
requirements.’’
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requirements related to safety of
persons.
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 § 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 NonCompliance 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.
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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
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.
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
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.
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.
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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 realtime 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 dayahead 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 multielement 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
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‘‘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.
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
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.’’
406 NOPR at P 976.
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not compromised and CEII information
remains confidential.
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 nextday 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.
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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 realtime 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.
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.
407 NOPR
at P 979.
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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.
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 BulkPower 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 § 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,
408 Id.
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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
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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 BulkPower System subject to Requirement
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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.
409 See
Order No. 890 at P 68–69, 207–213.
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. https://
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.
410 Id.
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16565
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.
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 BulkPower 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
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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 § 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.
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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
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.
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Reliability Standard is to maintain BulkPower 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
413 NOPR
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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.
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
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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 30minute period specified in Requirement
R4.
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
414 See
NOPR at P 995.
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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 § 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
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16567
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
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
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.
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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.
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.
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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.
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.
416 Requirement R4 states: ‘‘Each PurchasingSelling 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.’’
417 NOPR at P 1005.
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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 § 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.
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
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.
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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 realtime 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
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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 BulkPower 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
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–
419 We note that TOP–006–0 applies to
transmission operators, balancing authorities,
generator operators and reliability coordinators.
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006–1. In addition, pursuant to section
215(d)(5) of the FPA and § 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
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16569
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 NonCompliance and (2) includes reliability
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12. TPL: Transmission Planning
coordinators in the applicability
section.420
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
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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.
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.
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.
421 See NOPR at P 1035–36.
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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 selfassessment of regional reliability.423
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
422 See TPL–001–0, TPL–002–0, TPL–003–0 and
TPL–004–0.
423 See TPL–005–0 and TPL–006–0.
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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 eventbased 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.
(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
424 NOPR
at P 1042.
include practices cited in NERC’s
‘‘Examples of Excellence’’ found in its Readiness
Audits (available at https://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.
425 Examples
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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.
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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 BulkPower System. To achieve this goal, it
is necessary, among other things, to
ensure that the planning process and the
Reliability Standards produce a BulkPower 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
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16571
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.
(a) Comments
1696. Most of the commenters agree
with the Commission’s proposal on
sensitivity studies to determine critical
426 NOPR
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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 BulkPower 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.
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
427 Id.
at P 1061.
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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.
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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.
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.
1707. The Commission believes it is
important to clarify the type of analysis
428 Id.
at P 1061.
at n 324.
430 Id. at P 1046.
429 Id.
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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.
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
431 Id.
at P 1047.
at P 1049.
433 Section 215(a) of the FPA defines ‘‘Reliable
Operation’’ as ‘‘operating the elements of the BulkPower 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).
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432 Id.
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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
(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
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
434 With respect to failure, the element includes
a single transmission line, transformer, generator or
single pole of a DC line.
435 NOPR at P 1049.
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16573
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
436 Id.
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implementation of elements from other
Reliability Standards.
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.
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
437 National
Grid, MidAmerican and SDG&E.
438 NOPR at P 1049.
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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.
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
439 A ‘‘single element’’ means a transmission line,
a transformer, a generator or a single pole of a DC
line.
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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
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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
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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
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16575
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
(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.
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,
440 NOPR
at P 1060.
441 Id.
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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
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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 ‘‘nontransportable’’ 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 longrange 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
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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
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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
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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
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
442 See https://www.pjm.com/contributions/pjmmanuals/manuals.html.
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16577
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 BulkPower 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.
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.
443 See
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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
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(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
444 NOPR
at P 1063.
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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
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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.
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 longerterm planning horizons.
1759. The Requirements of TPL–001–
0 specify that the planning authority
and transmission planner must
445 Order
No. 890 at P 526, 542.
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.
446 The
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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
§ 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
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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
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.
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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.
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
450 See, e.g., EEI, APPA, SDG&E, Entergy, SoCal
Edison and TVA.
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16579
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.
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
451 NOPR
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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 BulkPower 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 oneyear or longer lead time, then the outage
of the transformer must be assessed
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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
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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.
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
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.
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enforceable. In addition, pursuant to
section 215(d)(5) of the FPA and
§ 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.
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
454 NOPR
at P 1081.
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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
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16581
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 rescheduling 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
455 Id.
at P 1084.
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.
456 From
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allowed after a Category B contingency,
which would be inconsistent with
Category C.3.
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
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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.
1789. The Commission agrees with
NRC that for operations purposes the N–
1 condition is always analyzed from the
457 10
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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
458 NOPR
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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.
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.
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
459 Id.
at P 1084.
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
460 ‘‘NERC
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16583
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.
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.
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.
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 (nonrecallable 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
NERC standards consider load shedding acceptable
for a single contingency.’’ NERC comments to the
Staff Preliminary Assessment at 57–58.
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.
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.
465 NOPR at P 1083.
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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.
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 BulkPower 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
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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
§ 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
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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
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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
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
466 Id.
at P 1097.
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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 BulkPower 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 BulkPower 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
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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
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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.
1821. The Commission disagrees with
LPPC that defining and documenting
proxies will result in the adoption of
467 Id.
at P 1098.
WECC Disturbance Performance Table W–
1 and Figure W–1 of Allowable Effects on other
Systems, NERC/WECC Planning Standards April
10, 2003.
468 See
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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
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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
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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
§ 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.
1831. FirstEnergy, EEI, APPA, TVA
and Northern Indiana all oppose the
469 See
NOPR at P 1112.
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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
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16587
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 SelfAssessment 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
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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.
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.
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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
470 Order
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.
No. 890 at P 443.
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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
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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 purchasingselling 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
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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 purchasingselling entities.
ii. Acceptable Ranges of Net Power
Factor Range
(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
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.
PO 00000
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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
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
473 NOPR
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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 nearsystem 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.
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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.
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
475 See
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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 clearlydefined 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 realtime 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 commerciallyavailable tools to provide real-time
transient stability assessments as part of
an integrated energy management
system for operators. APPA notes that
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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 steadystate 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
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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
476 See FERC Staff Report, Principles of Efficient
and Reliable Reactive Power Supply and
Consumption (2005), available at https://
www.ferc.gov/legal/staff-reports.asp.
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16591
the technical capability requirements for
using controllable load as a reactive
resource in the applicable Reliability
Standards.
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 § 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
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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 NonCompliance 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.
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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
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18:02 Apr 03, 2007
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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.
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 commonlyused 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
477 NOPR
PO 00000
478 See, e.g., MOD–001–0, TOP–002–1 and the
INT Reliability Standards.
at P 42–43.
Frm 00178
Fmt 4701
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
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,
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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 § 39.6 of
the Commission’s regulations.479
1899. In conclusion, the Commission
approves the glossary. Further, pursuant
to section 215(d)(5) of the FPA and
§ 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).
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
Number of
respondents
ycherry on PROD1PC64 with RULES2
Data collection
FERC–725A
Investor Owned Utilities ............................................................................
Municipals and Cooperatives—Large .......................................................
Municipals and Cooperatives—Small .......................................................
Generator Operators ................................................................................
479 18
481 44
480 5
CFR 39.6 (2006).
CFR 1320.11.
the Commission to manage a quality
compliance program as discussed in the
ERO’s Sanction Guidelines.482
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.
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
responses
170
80
670
360
Hours per
response
1
1
1
1
482 Wisconsin
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PO 00000
U.S.C. 3507(d) (2000).
Electric at 9.
Frm 00179
Fmt 4701
Sfmt 4700
16593
483 NOPR
E:\FR\FM\04APR2.SGM
at P 1157.
04APR2
2,080
1,420
710
500
Total annual
hours
353,600
113,600
475,700
180,000
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Number of
respondents
Data collection
Power Marketers ......................................................................................
Recordkeeping ..........................................................................................
Totals .................................................................................................
Number of
responses
159
1
Investor Owned Utilities
Munis/Coops (Large)
Munis/Coops (Small)
Generator Owner/Ops.
Power Marketers
........................ ........................
Hours per
response
100
........................
........................
........................
........................
........................
........................
Total annual
hours
15,900
35,360
11,360
47,570
18,000
1,590
1,252,680
ycherry on PROD1PC64 with RULES2
(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:
Reporting = 1,138,800 @ $114/hour =
$129,823,200
1,138,800 hours @ $114 per hour
(average cost of attorney ($200 per
hour), consultant ($150), technical ($80)
and administrative support ($25)).
Recordkeeping = 113,880 @ $17/hour
= $1,935,960
113,880 hours @ $17 per hour (file/
record clerk @ $17 an hour)
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, https://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.
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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 BulkPower 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
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).
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procedural, for information gathering,
analysis, and dissemination.485
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.
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
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
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
485 18
CFR 380.4(a)(5).
U.S.C. 601–612 (2006).
487 5 U.S.C. 601–604.
488 5 U.S.C. 603(a).
489 5 U.S.C. 605(b).
490 5 U.S.C. 609(a).
491 5 U.S.C. 611.
486 5
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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
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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.
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
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).
494 NOPR at P 1175.
495 Id. at 1176.
496 Id. at 49–53 (Section B.3 ‘‘Applicability to
Small Entities’’).
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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 reliabilityrelated 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.
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
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
497 Id.
at 51.
498 APPA/NRECA
comments at 2.
499 Id.
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16595
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
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other commenters discuss these
proposals in their comments, which the
Commission addresses in the
Applicability Issues section of the Final
Rule.500
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.
2. Commission Response
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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.
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
500 See Applicability Issues: Bulk-Power System
v. Bulk Electric System and Applicability to Small
Entities, supra sections II.C.1–2.
501 TAPS at 13.
502 NOPR at P 49–53.
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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.
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 BulkPower System. The term ‘‘Reliable
503 As noted previously, APPA, NRECA and TAPs
submitted supplemental comments supporting the
ERO’s compliance registry process.
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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.
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 BulkPower 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
504 16
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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.
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.
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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
505 See
16 U.S.C. 824o(d)(5) (2006).
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16597
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.
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.
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.
506 See Energy Information Administration
Database, Form EIA–861, Dept. of Energy (2005),
available at https://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.
508 See NERC Statement of Compliance Registry
Criteria (Revision 3) at 6–8.
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
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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.
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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 (https://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.
In consideration of the foregoing, the
Commission amends Chapter I, Title 18,
Code of Federal Regulations, by adding
Part 40 to read as follows:
I
PART 40—MANDATORY RELIABILITY
STANDARDS FOR THE BULK-POWER
SYSTEM
Sec.
40.1
40.2
40.3
Applicability.
Mandatory Reliability Standards.
Availability of Reliability Standards.
Authority: 16 U.S.C. 824o.
§ 40.1
Applicability.
(a) This part applies to all users,
owners and operators of the Bulk-Power
System within the United States (other
than Alaska or Hawaii), including, but
not limited to, entities described in
section 201(f) of the Federal Power Act.
(b) Each Reliability Standard made
effective by § 40.2 must identify the
subset of users, owners and operators of
the Bulk-Power System to which a
particular Reliability Standard applies.
§ 40.2
Mandatory Reliability Standards.
(a) Each applicable user, owner or
operator of the Bulk-Power System must
comply with Commission-approved
Reliability Standards developed by the
Electric Reliability Organization.
(b) A proposed modification to a
Reliability Standard proposed to
become effective pursuant to § 39.5 of
this Chapter will not be effective until
approved by the Commission.
§ 40.3
Availability of Reliability Standards.
The Electric Reliability Organization
must 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
Title
BAL–001–0 ....................
BAL–002–0 ....................
BAL–003–0 ....................
BAL–004–0 ....................
BAL–005–0 ....................
BAL–006–1 ....................
CIP–001–1 ....................
COM–001–1 ..................
COM–002–2 ..................
EOP–001–0 ...................
EOP–002–2 ...................
EOP–003–1 ...................
EOP–004–1 ...................
EOP–005–1 ...................
EOP–006–1 ...................
EOP–007–0 ...................
ycherry on PROD1PC64 with RULES2
Reliability standard
Real Power Balancing Control Performance ........................................
Disturbance Control Performance .........................................................
Frequency Response and Bias .............................................................
Time Error Correction ............................................................................
Automatic Generation Control ...............................................................
Inadvertent Interchange ........................................................................
Sabotage Reporting ..............................................................................
Telecommunications .............................................................................
Communications and Coordination .......................................................
Emergency Operations Planning ..........................................................
Capacity and Energy Emergencies .......................................................
Load Shedding Plans ............................................................................
Disturbance Reporting ..........................................................................
System Restoration Plans .....................................................................
Reliability Coordination—System Restoration ......................................
Establish, Maintain, and Document a Regional Blackstart Capability
Plan.
Plans for Loss of Control Center Functionality .....................................
Documentation of Blackstart Generating Unit Test Results .................
Facility Connection Requirements ........................................................
Coordination of Plans for New Facilities ...............................................
Transmission Vegetation Management Program ..................................
Methodologies for Determining Electrical Facility Ratings ....................
Electrical Facility Ratings for System Modeling ....................................
Facility Ratings Methodology ................................................................
Establish and Communicate Facility Ratings ........................................
Transfer Capabilities Methodology ........................................................
EOP–008–0
EOP–009–0
FAC–001–0
FAC–002–0
FAC–003–1
FAC–004–0
FAC–005–0
FAC–008–1
FAC–009–1
FAC–012–1
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Approve.
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Pending.
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
direct
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
Approve; direct
Approve.
Approve.
Approve; direct
Approve; direct
Withdrawn.
Withdrawn.
Approve; direct
Approve.
Pending.
modification.
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Reliability standard
Title
FAC–013–1 ...................
INT–001–2 .....................
INT–002–0 .....................
INT–003–2 .....................
INT–004–1 .....................
INT–005–1 .....................
INT–006–1 .....................
INT–007–1 .....................
INT–008–1 .....................
INT–009–1 .....................
INT–010–1 .....................
IRO–001–1 ....................
IRO–002–1 ....................
IRO–003–2 ....................
IRO–004–1 ....................
IRO–005–1 ....................
IRO–006–3 ....................
IRO–014–1 ....................
Establish and Communicate Transfer Capabilities ...............................
Interchange Transaction Tagging .........................................................
Interchange Transaction Tag Communication and Assessment ..........
Interchange Transaction Implementation ..............................................
Interchange Transaction Modifications .................................................
Interchange Authority Distributes Arranged Interchange ......................
Response to Interchange Authority ......................................................
Interchange Confirmation ......................................................................
Interchange Authority Distributes Status ..............................................
Implementation of Interchange .............................................................
Interchange Coordination Exceptions ...................................................
Reliability Coordination—Responsibilities and Authorities ....................
Reliability Coordination—Facilities ........................................................
Reliability Coordination—Wide Area View ............................................
Reliability Coordination—Operations Planning .....................................
Reliability Coordination—Current Day Operations ................................
Reliability Coordination—Transmission Loading Relief ........................
Procedures, Processes, or Plans to Support Coordination Between
Reliability Coordinators.
Notifications and Information Exchange Between Reliability Coordinators.
Coordination of Real-time Activities Between Reliability Coordinators
Documentation of TTC and ATC Calculation Methodologies ...............
Review of TTC and ATC Calculations and Results ..............................
Procedure for Input on TTC and ATC Methodologies and Values ......
Documentation of Regional CBM Methodologies .................................
Procedure for Verifying CBM Values ....................................................
Procedures for Use of CBM Values ......................................................
Documentation of the Use of CBM .......................................................
Documentation and Content of Each Regional TRM Methodology ......
Procedure for Verifying TRM Values ....................................................
Steady-State Data for Transmission System Modeling and Simulation
Regional Steady-State Data Requirements and Reporting Procedures
Dynamics Data for Transmission System Modeling and Simulation ....
RRO Dynamics Data Requirements and Reporting Procedures ..........
Development of Interconnection-Specific Steady State System Models.
Development of Interconnection-Specific Dynamics System Models ...
Actual and Forecast Demands, Net Energy for Load, Controllable
DSM.
Aggregated Actual and Forecast Demands and Net Energy for Load
Reports of Actual and Forecast Demand Data .....................................
Forecasts of Interruptible Demands and DCLM Data ..........................
Providing Interruptible Demands and DCLM Data ...............................
Accounting Methodology for Effects of Controllable DSM in Forecasts
Verification of Generator Gross and Net Real Power Capability .........
Verification of Generator Gross and Net Reactive Power Capability ...
Operating Personnel Responsibility and Authority ...............................
Operating Personnel Training ...............................................................
Operating Personnel Credentials ..........................................................
Reliability Coordination—Staffing ..........................................................
System Protection Coordination ...........................................................
Define and Document Disturbance Monitoring Equipment Requirements.
Regional Requirements for Analysis of Misoperations of Transmission and Generation Protection Systems.
Analysis and Mitigation of Transmission and Generation Protection
System Misoperations.
Transmission and Generation Protection System Maintenance and
Testing.
Development and Documentation of Regional UFLS Programs ..........
Assuring Consistency with Regional UFLS Program ...........................
Underfrequency Load Shedding Equipment Maintenance Programs ..
UFLS Performance Following an Underfrequency Event .....................
Assessment of the Design and Effectiveness of UVLS Program .........
UVLS System Maintenance and Testing ..............................................
Special Protection System Review Procedure .....................................
Special Protection System Database ...................................................
Special Protection System Assessment ...............................................
Special Protection System Data and Documentation ...........................
Special Protection System Misoperations .............................................
Special Protection System Maintenance and Testing ..........................
IRO–015–1 ....................
IRO–016–1 ....................
MOD–001–0 ..................
MOD–002–0 ..................
MOD–003–0 ..................
MOD–004–0 ..................
MOD–005–0 ..................
MOD–006–0 ..................
MOD–007–0 ..................
MOD–008–0 ..................
MOD–009–0 ..................
MOD–010–0 ..................
MOD–011–0 ..................
MOD–012–0 ..................
MOD–013–1 ..................
MOD–014–0 ..................
MOD–015–0 ..................
MOD–016–1 ..................
MOD–017–0 ..................
MOD–018–0 ..................
MOD–019–0 ..................
MOD–020–0 ..................
MOD–021–0 ..................
MOD–024–1 ..................
MOD–025–1 ..................
PER–001–0 ...................
PER–002–0 ...................
PER–003–0 ...................
PER–004–1 ...................
PRC–001–1 ...................
PRC–002–1 ...................
PRC–003–1 ...................
PRC–004–1 ...................
ycherry on PROD1PC64 with RULES2
PRC–005–1 ...................
PRC–006–0
PRC–007–0
PRC–008–0
PRC–009–0
PRC–010–0
PRC–011–0
PRC–012–0
PRC–013–0
PRC–014–0
PRC–015–0
PRC–016–0
PRC–017–0
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...................
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Approve; direct
Approve; direct
Withdrawn.
Approve.
Approve.
Approve.
Approve; direct
Approve.
Approve.
Approve.
Approve.
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve; direct
Approve.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
modification.
Approve.
Approve.
Pending; direct modification.
Pending.
Pending.
Pending; direct modification.
Pending.
Approve; direct modification.
Approve; direct modification.
Pending; direct modification.
Pending.
Approve; direct modification.
Pending; direct modification.
Approve; direct modification.
Pending; direct modification.
Pending; direct modification.
Pending; direct modification.
Approve; direct modification.
Approve; direct modification.
Approve.
Approve; direct modification.
Approve; direct modification.
Approve; direct modification.
Pending.
Pending; direct modification.
Approve.
Approve; direct modification.
Approve; direct modification.
Approve; direct modification.
Approve; direct modification.
Pending.
Pending.
Approve.
Approve; direct modification.
Pending.
Approve.
Approve;
Approve.
Approve;
Approve;
Pending.
Pending.
Pending.
Approve.
Approve.
Approve;
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direct modification.
direct modification.
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APPENDIX A.—DISPOSITION OF RELIABILITY STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES—Continued
Reliability standard
Title
PRC–018–1 ...................
PRC–020–1 ...................
PRC–021–1 ...................
PRC–022–1 ...................
TOP–001–1 ...................
TOP–002–2 ...................
TOP–003–0 ...................
TOP–004–1 ...................
TOP–005–1 ...................
TOP–006–1 ...................
TOP–007–0 ...................
TOP–008–1 ...................
TPL–001–0 ....................
TPL–002–0 ....................
TPL–003–0 ....................
TPL–004–0 ....................
TPL–005–0 ....................
TPL–006–0 ....................
VAR–001–1 ...................
VAR–002–1 ...................
Glossary ........................
Regional Difference .......
Regional Difference .......
Regional Difference .......
Regional Difference .......
Disturbance Monitoring Equipment Installation and Data Reporting ....
Undervoltage Load Shedding Program Database ................................
Undervoltage Load Shedding Program Data ........................................
Undervoltage Load Shedding Program Performance ...........................
Reliability Responsibilities and Authorities ............................................
Normal Operations Planning .................................................................
Planned Outage Coordination ...............................................................
Transmission Operations ......................................................................
Operational Reliability Information ........................................................
Monitoring System Conditions ..............................................................
Reporting SOL and IROL Violations .....................................................
Response to Transmission Limit Violations ..........................................
System Performance Under Normal Conditions ...................................
System Performance Following Loss of a Single BES Element ..........
System Performance Following Loss of Two or More BES Elements
System Performance Following Extreme BES Events .........................
Regional and Interregional Self-Assessment Reliability Reports .........
Assessment Data from Regional Reliability Organizations ..................
Voltage and Reactive Control ...............................................................
Generator Operations for Maintaining Network Voltage Schedules .....
Glossary of Terms Used in Reliability Standards .................................
BAL–001:ERCOT:CPS2 ........................................................................
BAL–006: MISO RTO inadvertent Interchange Accounting .................
BAL–006: MISO/SPP Financial Inadvertent Settlement .......................
INT–001/4: WECC Tagging Dynamic Schedules and Inadvertent
Payback.
INT–001/3:MISO Energy Flow Information ...........................................
INT–003: MISO/SPP Scheduling Agent ...............................................
INT–003: MISO Enhanced Scheduling Agent ......................................
IRO–006: PJM/MISO/SPP Enhanced Congestion Management .........
Regional
Regional
Regional
Regional
Difference
Difference
Difference
Difference
.......
.......
.......
.......
Proposed disposition
Approve.
Pending.
Approve.
Approve.
Approve;
Approve;
Approve;
Approve;
Approve;
Approve;
Approve.
Approve.
Approve;
Approve;
Approve;
Approve;
Pending.
Pending.
Approve;
Approve.
Approve;
Approve;
Approve.
Approve.
Pending.
direct
direct
direct
direct
direct
direct
modification.
modification.
modification.
modification.
modification.
modification.
direct
direct
direct
direct
modification.
modification.
modification.
modification.
direct modification.
direct modification.
direct modification.
Approve.
Approve.
Approve.
Pending.
APPENDIX B.—COMMENTERS ON NOTICE OF PROPOSED RULEMAKING
Abbreviation
Entity
Alberta ESO .......................................................................
ALCOA ...............................................................................
Allegheny ............................................................................
AMP Ohio ...........................................................................
APPA ..................................................................................
APPA/NRECA ....................................................................
ATC ....................................................................................
Avista/Puget .......................................................................
BPA ....................................................................................
CAISO ................................................................................
California Cogernation .......................................................
Alberta Electric System Operator.
Alcoa, Inc. and Alcoa Power Generating Company.
Allegheny Power and Allegheny Energy Supply Company, LLC.
American Municipal Power—Ohio, Inc.
American Public Power Association.
APPA/NRECA.
American Transmission Company, LLC.
Avista Corporation and Puget Sound Energy, Inc.
Bonneville Power Administration.
California Independent System Operator Corporation.
Cogeneration Association of California and the Energy Producers and Users Coalition.
Public Utilities Commission of the State of California.
Canadian Electricity Association.
City of Cleveland, Division of Cleveland Public Power.
Comverge, Inc.
Richard Blumenthal, Attorney General for the State of Connecticut.
Connecticut Department of Public Utility Control.
Constellation Energy Group.
Dominion Resources Services, Inc.
Duke Energy Corporation.
Dynegy, Inc.
Edison Electric Institute.
Electricity Consumers Resource Council.
Entergy Services, Inc.
Electric Power Supply Association.
Electric Reliability Council of Texas, Inc.
Fertilizer Institute.
FirstEnergy Service Company.
City of Acworth.
City of Adel.
City of Blakely.
City of Cairo.
City of Calhoun.
City of Camilla.
City of College Park.
ycherry on PROD1PC64 with RULES2
California PUC ...................................................................
CEA ....................................................................................
Cleveland Public Power .....................................................
Comverge ...........................................................................
Connecticut Attorney General* ..........................................
Connecticut DPUC* ............................................................
Constellation .......................................................................
Dominion ............................................................................
Duke ...................................................................................
Dynegy ...............................................................................
EEI ......................................................................................
ELCON ...............................................................................
Entergy ...............................................................................
EPSA ..................................................................................
ERCOT ...............................................................................
Fertilizer Institute ................................................................
FirstEnergy .........................................................................
Georgia Cities ....................................................................
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APPENDIX B.—COMMENTERS ON NOTICE OF PROPOSED RULEMAKING—Continued
Abbreviation
Entity
Georgia Operators .............................................................
International Transmission .................................................
ISO/RTO Council ...............................................................
ISO–NE ..............................................................................
KCP&L ................................................................................
LPPC ..................................................................................
Manitoba .............................................................................
Marshall Municipal Utility Group Massachusetts DTE .......
MEAG Power .....................................................................
MidAmerican ......................................................................
Mid-Continent .....................................................................
MISO–PJM .........................................................................
ycherry on PROD1PC64 with RULES2
MRO ...................................................................................
NARUC ...............................................................................
National Grid ......................................................................
NCPA .................................................................................
NERC .................................................................................
New
England
Conference
of
Public
Utilities
Commissioners*.
New York Commission .......................................................
New York Public Power .....................................................
New York TOs ....................................................................
Nevada Companies ............................................................
Northeast Utilities ...............................................................
Northern Indiana ................................................................
Northwest Requirements Utilities .......................................
NPCC .................................................................................
NRC ....................................................................................
NRECA ...............................................................................
NYSRC ...............................................................................
NY Major Consumers .........................................................
Ontario IESO ......................................................................
Otter Tail ............................................................................
PG&E .................................................................................
Portland General ................................................................
Process Electricity Committee ...........................................
Progress Energy ................................................................
ReliabilityFirst .....................................................................
Reliant ................................................................................
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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 System Operators Corp.
International Transmission Company.
ISO/RTO Council.
ISO New England, Inc.
Kansas City Power and Light Company.
Large Public Power Council.
Manitoba Hydro.
Massachusetts Department of Telecommunications and Energy.
MEAG Power.
MidAmerican Electric Operating Companies.
Mid-Continent Systems Group.
Midwest Independent Transmission System Operator, Inc. and PJM Interconnection,
L.L.C.
Midwest Reliability Organization.
National Association of Regulatory Utility Commissioners.
National Grid USA.
Northern California Power Agency.
North American Electric Reliability Corp.
New England Conference of Public Utilities Commissioners, Inc.
New York State Public Service Commission.
New York Association of Public Power.
New York Transmission Owners.
Nevada Power Company and Sierra Pacific Power Company.
Northeast Utilities Service Company.
Northern Indiana Public Service Company.
Northwest Requirements Utilities.
Northeast Power Coordinating Council: Cross-Border Regional Entity, Inc.
United States Nuclear Regulatory Commission.
National Rural Electric Cooperative Association.
New York State Reliability Council, LLC.
Multiple Intervenors, an unincorporated association of approximately 55 large industrial, commercial and institutional end-use energy consumers with facilities in New
York.
Ontario Independent Electricity System Operator.
Otter Tail Power Company.
Pacific Gas and Electric Company.
Portland General Electric Company.
Process Gas Consumers Group Electricity Committee.
Progress Energy, Inc.
ReliabilityFirst Corporation.
Reliant Energy, Inc.
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APPENDIX B.—COMMENTERS ON NOTICE OF PROPOSED RULEMAKING—Continued
Abbreviation
Entity
Santa Clara ........................................................................
SDG&E ...............................................................................
SERC .................................................................................
Six Cities ............................................................................
SMA ....................................................................................
Small Entities Forum ..........................................................
SoCal Edison .....................................................................
South Carolina E&G ...........................................................
Southern .............................................................................
Southwest TDUs ................................................................
STI Capital .........................................................................
Tacoma ..............................................................................
TANC ..................................................................................
TAPS ..................................................................................
TVA ....................................................................................
Utah Municipal Power ........................................................
Valley Group ......................................................................
WECC ................................................................................
WIRAB advice ....................................................................
Wisconsin Electric ..............................................................
Xcel ....................................................................................
City of Santa Clara, California.
San Diego Gas and Electric Company.
SERC Reliability Corporation.
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California.
Steel Manufacturers Association.
ReliabilityFirst Corporation Small Entities Forum.
Southern California Edison Company.
South Carolina Electric and Gas Company.
Southern Company Services, Inc.
Southwest Transmission Dependent Utility Group.
STI Capital Company.
Tacoma Power.
Transmission Agency of Northern California.
Transmission Access Policy Study Group.
Tennessee Valley Authority.
Utah Associated Municipal Power Systems.
The Valley Group, Inc.
Western Electricity Coordinating Council.
Western Interconnection Regional Advisory Body.
Wisconsin Electric Power Company.
Xcel Energy Services.
*Comments filed out-of-time.
APPENDIX C: ABBREVIATIONS IN THIS DOCUMENT
ACE ..................................................................................................................................
AGC .................................................................................................................................
ANSI .................................................................................................................................
ATC ..................................................................................................................................
BCP ..................................................................................................................................
CBM .................................................................................................................................
CPS ..................................................................................................................................
DC ....................................................................................................................................
DCS ..................................................................................................................................
DSM .................................................................................................................................
ERO .................................................................................................................................
GWh .................................................................................................................................
IEEE .................................................................................................................................
IROL .................................................................................................................................
LSE ..................................................................................................................................
MVAR ...............................................................................................................................
MW ...................................................................................................................................
ROW ................................................................................................................................
SOL ..................................................................................................................................
SPS ..................................................................................................................................
TIS ....................................................................................................................................
TLR ..................................................................................................................................
TRM .................................................................................................................................
TTC ..................................................................................................................................
UFLS ................................................................................................................................
UVLS ................................................................................................................................
Area Control Error.
Automatic Generation Control.
American National Standards Institute.
Available Transfer Capability.
Blackstart Capability Plan.
Capacity Benefit Margin.
Control Performance Standard.
Direct Current.
Disturbance Control Standard.
Demand-Side Management.
Electric Reliability Organization.
Gigawatt hour.
Institute of Electrical and Electronics Engineers.
Interconnection Reliability Operating Limits.
Load-serving Entity.
Mega Volt Ampere Reactive.
Mega Watt.
Right of Way.
System Operating Limit.
Special Protection System.
Transmission Issues Subcommittee.
Transmission Loading Relief.
Transmission Reliability Margin.
Total Transfer Capability.
Underfrequency Load Shedding.
Undervoltage Load Shedding.
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04APR2
Agencies
[Federal Register Volume 72, Number 64 (Wednesday, April 4, 2007)]
[Rules and Regulations]
[Pages 16416-16602]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E7-5284]
[[Page 16415]]
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Part II
Department of Energy
-----------------------------------------------------------------------
Federal Energy Regulatory Commission
-----------------------------------------------------------------------
18 CFR Part 40
Mandatory Reliability Standards for the Bulk-Power System; Final Rule
Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules
and Regulations
[[Page 16416]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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
[[Page 16417]]
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.
---------------------------------------------------------------------------
\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 https://www.ferc.gov/cust-protect/
moi/blackout.asp.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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
[[Page 16418]]
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\13\ 18 CFR 39.5(e).
---------------------------------------------------------------------------
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, https://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.
---------------------------------------------------------------------------
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
[[Page 16419]]
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\19\ NOPR at P 14.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
25. Third, section 215 of the FPA explains that the Bulk-Power
System broadly encompasses both the facilities
[[Page 16420]]
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\
---------------------------------------------------------------------------
\23\ 16 U.S.C. 824o(a)(1).
\24\ 16 U.S.C. 824o(a)(5).
\25\ 16 U.S.C. 824o(a)(8).
---------------------------------------------------------------------------
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.
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\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).
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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'' be