20171218PAC to Staff Attachment-4 Utah.pdf

PEAKRELIABILITY
assuring the wide area view
SYSTEM OPERATING LIMITS
METHODOLOGY FOR THE
OPERATIONS HORIZON
Rev.8.1
By
Peak Reliability
February 24,2017
PEAK RELIABILITY -RELIABILITY COORDINATION
www.peakrc.com.
Version 8.1
PEAKRELIABILITY SOL Methodologyfor the Operations
Horizon FAC-011-3
FAC-014-2
Table of Contents
A.Conventions ..................................................................................4
B.Introduction and Purpose ............................................................................4
C.Applicability ................................................................................4
D.Drivers for the 2016 Major SOL Methodology Revision ..........................................5
E.The Evolution of SOLs in the Western Interconnection...........................................5
F.A Shift in Operations Paradigm ........................................................................7
G.SOL Versus TTC................................................................................10
H.Role of WECC Path Ratings.........................................................................12
l.SOLs Versus Mechanisms to Prevent Limit Exceedance -the Role of Operating Plans..13
J.The Role of Nomograms and TTC in Operations Reliability..............................................14
K.Path Operators,Path Operations,and TOP-007-WECC-1a .............................................15
L.Acceptable System Performance ..............................................................16
M.Multiple Contingencies (MC)in Operations.................................................19
N.SOL Exceedance .............................................................................25
O.Allowed Uses of Automatic Mitigation Schemes in the Operations Horizon ......................26
P.Coordination Responsibilities .....................................................................31
Q.SOLs Used in the Operations Horizon.........................................................32
Facility Ratings.............................................................................32
System Voltage Limits ............................................................................35
Stability Limitations................................................................................39
R.System Stressing Methodology .................................................................46
S.Instability,Cascading,Uncontrolled Separation and IROLs.............................................50
T.IROL Establishment ...............................................................................54
U.IROL Tv in the Peak RC Area.............................................................................64
V.Peak's Process for Addressing IROLs Established by Planning Coordinators (PC)and
Transmission Planners (TP).............................................................................64
W.Peak's Role In Ensuring SOLs are Established Consistent with the SOL Methodology ....65
X.System Study Models [NERC Standard FAC-011-3 R3.4]............................................66
Y.TOP Communication of SOLs to Peak .................................................................66
Z.RC Communication of SOL and IROL Information to Other Functional Entities................67
Contact Information................................................................................67
Version History......................................................................................68
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Appendix A ...........................................................................70
Appendix B ............................................................................72
Appendix C ............................................................................73
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A.Conventions
When a term from the North American Electric Reliability Corporation (NERC)Glossary of
Terms is used in this document,the term will be capitalized.Examples include:Facility,
Facility Rating,Contingency and Real-time.Other capitalized terms are defined in this
document;for example,System Voltage Limit is a capitalized term defined and used in this
document.Such capitalized terms used in the SOL Methodology are listed in Appendix A.
B.Introduction and Purpose
This document is the Peak Reliability Coordinator (RC)System Operating Limit (SOL)
Methodology for the Operations Horizon [NERC Standard FAC-011-3 R1].The document
establishes the methodology to be used in the Peak RC Area for determining SOLs and
Interconnection Reliability Operating Limits (IROL)for use in the Operations Horizon pursuant
to North American Electric Reliability Corporation (NERC)Reliability Standards FAC-011-3
and FAC-014-2.
Reliable operation of the Bulk Electric System (BES)in the Peak RC Area requires that all
Transmission Operators (TOP)and the RC meet the minimum requirements stipulated in this
SOL Methodology.It is not the intent of this SOL Methodology to limit the nature and range of
studies and analyses TOPs and the RC may perform in ensuring acceptable system
performance throughout the Operations Horizon.
The ultimate task of TOPs and the RC is to continually assess and evaluate projected system
conditions as Real-time approaches with the objective of ensuring acceptable system
performance in Real-time.These assessments are performed in an iterative fashion within the
Operations Horizon,typically beginning as part of seasonal planning studies,followed by
assessments performed as part of the IRO-017-1 Outage Coordination Process,followed by
Operational Planning Analyses (OPA),and ultimately concluding with Real-time Assessments
(RTA).Accordingly,these iterative studies should use anticipated transmission system
configuration,generation dispatch and load levels,which are expected to improve in accuracy
as Real-time approaches [NERC Standard FAC-011-3 R3.6].
C.Applicability
This SOL Methodology applies to the following entities within the Peak RC Area for
developing SOLs and IROLs used in the Operations Horizon [NERC Standard FAC-011-3
R1.1]:
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TOPs
Peak RC
This SOL Methodology defines Operations Horizon as follows:
A rolling 12-month period starting at Real-time (now)through the last hour of the twelfth
month into the future.
Because the SOL Methodology is applicable to the Operations Horizon,the concepts in this
SOL Methodology apply to all sub-horizons within the Operations Horizon -seasonal
planning,outage coordination,next-day,same-day and Real-time.
D.Drivers for the 2016 Major SOL Methodology Revision
The NERC-defined term SOL is used extensively in the NERC Reliability Standards;however,
there has historically been much confusion with,and many widely varied interpretations and
applications of,the SOL term.The prevalent confusion in the industry prompted the NERC
Project 2014-03 Revisions to TOP and IRO Reliability Standards to issue the White Paper
entitled,"System Operating Limit Definition and Exceedance Clarification."This White Paper
served as a conceptual basis for developing the TOP and IRO Reliability Standards that have
an effective date of April 1,2017.Consequently,the NERC SOL White Paper,along with the
WECC standing committee-approved Path Operator Task Force (POTF)recommendation,
served as the conceptual basis for the 2016 major revision of the SOL Methodology for the
Operations Horizon.
E.The Evolution of SOLs in the Western Interconnection
Much of the confusion associated with the SOL term in the West is due to the fact that
changes have occurred in Peak's SOL Methodology over the last few years that differ from the
historical paradigms and practices that have been in place in the West for a number of years.
The SOL term as historically applied in the West has roots in the Operational Transfer
Capability (OTC)concept that was reflected in the Reliability Management System (RMS)
program in the late 1990s.The original RMS and subsequent regional reliability standard
TOP-STD-007-0 required operation within OTC for the Paths listed in the "Major WECC
Transfer Paths in the Bulk Electric System."
The OTC was a pre-determined Transfer Capability value which,if operated within,intended
to prevent a predetermined limiting Contingency from resulting in exceedance of an identified
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thermal Facility Rating,System Voltage Limit or violation of stability criteria.For example,a
thermally limited OTC was a Transfer Capability value that prevented an identified
Contingency from causing exceedance of an identified Facility's Emergency Rating.
When TOP-STD-007-0 was revised as TOP-007-WECC-1,the guidance from NERC was to
avoid the use of undefined terms such as OTC and to instead use approved NERC terms.The
new concept of an SOL as established in several NERC FAC standards was beginning to
emerge,and the conservative approach of replacing all references to OTC with the NERC
term SOL was taken,even though OTC is more closely related to the NERC term Total
Transfer Capability (TTC)than to System Operating Limit (SOL).The 30-minute time limit
referenced in TOP-007-WECC-1 recognized that,if a Contingency event resulted in an SOL
(OTC)exceedance,some reasonable time was needed to bring the system back to within the
pre-determined SOL (OTC).
With respect to the 40 Paths listed in the "Major WECC Transfer Paths in the Bulk Electric
System,"the selection of these Paths also originated in the RMS program.There are no
records of any technical criteria that resulted in the establishment of the list of Paths or why
these particular Paths were selected and others were not.In Federal Energy Regulatory
Commission (FERC)Order 752,FERC directed WECC to develop a means to provide
consistency and transparency when making revisions to the list.WECC committed to publicly
post any revisions to the WECC Transfer Path Table on the WECC website with concurrent
notification to the Commission,NERC and industry.WECC has not changed the list of Paths
since TOP-007-WECC-1 was approved by FERC in 2011.
Historically,the four subregional study groups have performed seasonal studies for WECC
Paths to determine a seasonal "Path SOL"and corresponding Operating Procedures.A
primary objective of these seasonal studies was to confirm that the WECC Path Rating was
achievable,given the expected system conditions for that season.If seasonal studies
demonstrated that the WECC Path Rating was expected to be achievable for that season,the
WECC Path Rating was deemed to be the Path SOL for the season.If seasonal studies
reached the WECC Path Rating (plus some margin)without encountering pre-or post-
Contingency reliability issues,the Path was considered to be "flow limited".In such cases,the
"flow limited"WECC Path Rating served as the seasonal Path SOL.If seasonal studies could
not demonstrate that the WECC Path Rating was expected to be achievable for that season,
the subregional study group would determine a lesser Path flow value that provided for
acceptable thermal,voltage and stability criteria performance for the pre-and post-
Contingency state.This value then was deemed to be the Path SOL for the season.Seasonal
Path SOLs typically served as operational caps for the season.
Through the WECC POTF initiative,the new TOPllRO standards and the accompanying
NERC SOL White Paper,the industry has a much better understanding of what an SOL is,
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how the SOL term should be applied and how SOLs should be addressed in operations.As a
result,the industry now realizes that there is no reason Facilities comprising these 40 Paths
should be treated any differently than all the other elements of the BES.The new TOP and
IRO Reliability Standards and the corresponding concepts in the 2016 major revision of the
SOL Methodology represent a more accurate and reliable approach to achieving the ultimate
reliability objective of demonstrating acceptable pre-and post-Contingency performance in
operations than that characterized by the Path SOL paradigm.
The "RC Seasonal SOL Coordination Process"document referenced in the previous version
of the SOL Methodology (revision 7.1),while still applicable for seasonal planning and
coordination,is not referenced in this version of the SOL Methodology.TOPs are expected to
continue with the "RC Seasonal SOL Coordination Process"until a replacement process is
developed and implemented.
F.A Shift in Operations Paradigm
The WECC "Path SOL"concept embodies an operations paradigm characterized by the
following:
A study,assessment or analysis needs to be performed ahead of time to establish a
Path SOL that achieves acceptable BES performance (pursuant to FAC-011-3
Requirement R2).
The established Path SOL (a maximum flow value on an interface or cut plane)is
then communicated and coordinated with operators and other impacted entities prior
to implementation.
Path Operators are then given Operating Plans to operate below the Path SOL with
the presumption that doing so will result in acceptable pre-and post-Contingency
system performance in Real-time operations.
Historically,when a Path exceeded its Path SOL in Real-time operations,the general practice
was for the Path Operator to initiate actions to reduce that Path's flow below the Path SOL1.
1 A formal request for clarification that Requirement R1 applies "to Transmission Operators,as defined in
the NERC Glossary of Terms,and not to the path operators who have no compliance responsibilities
under TOP-007-WECC-1 (TOP),other than any responsibilities they may have as a Transmission
Operator for facilities in their respective Transmission Operator Areas."(Emphasis added.)was provided
in Appendix 1 of TOP-007-WECC-1a.The response to the request for clarification states,"The NERC
Functional Model 4,in effect at the time the standard was drafted,did not include Path Operators as an
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For the Paths listed in "Major WECC Transfer Paths in the Bulk Electric System"the Path SOL
exceedance was required to be mitigated within 30 minutes.In the past,extreme actions such
as load shedding has been exercised to mitigate Path SOL exceedances within 30 minutes,
even if Real-time Assessments did not confirm the presence of an actual reliability issue.
While aspects of the Path SOL approach may have merit in some respects,the totality of this
approach does not fully align with the principles characterized in the TOP and IRO standards,
which present a different approach to achieving the ultimate reliability objective of
demonstrating acceptable pre-and post-Contingency performance in operations:
Operations Planninq Time Horizon
1.IRO-017-1 requires Planning Coordinators (PC)and TPs to share annual Planning
Assessments with RCs (Requirement R3)and to jointly develop solutions with its
respective RC for identified issues or conflicts with planned outages in its Planning
Assessment for the Near-Term Transmission Planning Horizon (Requirement R4).
These requirements facilitate a transfer of information from planning to operations
with regard to outage planning.
2.IRO-017-1 requires RCs to develop,implement,and maintain an outage coordination
process (Requirement R1),and requires TOPs and Balancing Authorities (BA)to
follow the process (Requirement R2).These requirements improve outage
coordination within the operations planning time horizon leading up to Real-time
operations.
3.TOP-002-4 Requirement R1 and IRO-008-2 Requirement R1 require that the TOP
and RC have an Operational Planning Analysis (OPA)to identify SOL exceedances.
Note that SOL exceedance is described in the NERC SOL White Paper and that the
revised definition of OPA addresses both the pre-and post-Contingency states.
4.TOP-002-4 Requirement R2 and IRO-008-2 Requirement R2 require that the TOP
and RC have Operating Plan(s)to address potential SOL exceedances identified in
the OPA.
5.TOP-002-4 Requirement R3 and IRO-008-2 Requirement R3 require that the TOP
and RC notify entities identified in the Operating Plan(s)as to their role in those
plan(s).
approved applicable entity;therefore,the document only applies to the stated Transmission Operators
and does not apply to Path Operators."
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6.TOP-002-4 Requirement R6 requires that the TOP provide its Operating Plan(s)for
next-day operations to its RC.
Same Day and Real-time Time Horizons
7.TOP-001-3 Requirement R13 and IRO-008-2 Requirement R4 require that the TOP
and RC ensure that a Real-time Assessment (RTA)is performed at least once every
30 minutes.Note that the revised definition of RTA addresses both the pre-and post-
Contingency states.
8.TOP-001-3 Requirement R14 requires the TOP to initiate its Operating Plan to
mitigate an SOL exceedance identified as part of its Real-time monitoring or Real-
time Assessment.
9.IRO-008-2 Requirement R5 requires the RC to notify impacted TOPs and BAs within
its RC Area,and other impacted RCs as indicated in its Operating Plan,when the
results of an RTA indicate an actual or expected condition that results in,or could
result in,an SOL or IROL exceedance within its Wide Area.Note that the NERC SOL
White Paper describes SOL exceedance.
Advanced applications,such as state estimation and Real-time Contingency Analysis (RTCA),
which are widely used in the industry today,allow entities to assess pre-and post-
Contingency performance for identifying SOL exceedance and to identify potential Cascading
events in Real-time based on actual operating conditions.The TOP and IRO Reliability
Standards require that TOPs and RCs have OPAs and RTAs to assess actual and expected
system conditions for the pre-and post-Contingency states.The use of these technologies
today fall in line with the new TOP and IRO Reliability Standards and definitions and
requirements associated with OPA and RTA.The development and use of the Real-time tools
improve reliability and allow better use of the BES beyond what the historical Path SOL
concept permitted.The WECC Standing Committees'acceptance and endorsement of the
POTF White Paper at the October 2014 Standing Committee meetings is indicative of the
general belief that reliability can be improved and that operating efficiencies can be gained by
taking steps to move away from the historical operating paradigm characterized by the Path
SOL.This version of the SOL Methodology for the Operations Horizon represents one of
those steps.
In order to understand and appreciate the shift in operations paradigm,it is important to note a
few key definitions as found in the NERC Glossary of Terms:
Operational Transfer Capability (from the retired WECC standard TOP-STD-007-0):
The OTC is the maximum amount of actual power that can be transferred over direct or
parallel transmission elements comprising:
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An interconnection from one Transmission Operator area to another Transmission
Operator area;or
A transfer Path within a Transmission Operator area.
Transfer Capability (approved definition from the NERC Glossary of Terms):
The 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."
Total Transfer Capability (approved definition from the NERC Glossary of Terms):
The 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.
System Operating Limit (approved definition from the NERC Glossary of Terms):
The value (such as MW,MVar,Amperes,Frequency or Volts)that satisfies the most
limiting of the prescribed operating criteria for a specified system configuration to ensure
operation within acceptable reliability criteria.System Operating Limits are based upon
certain operating criteria.These include,but are not limited to:
Facility Ratings (Applicable pre-and post-Contingency equipment or Facility Ratings)
Transient Stability Ratings (Applicable pre-and post-Contingency Stability Limits)
Voltage Stability Ratings (Applicable pre-and post-Contingency Voltage Stability)
System Voltage Limits (Applicable pre-and post-Contingency Voltage Limits)
G.SOL Versus TTC
The foundational change with this SOL Methodology revision begins with the questions,"What
is an SOL?"and "What is not an SOL?"The core idea underpinning this revision to the SOL
Methodology is found in the clear distinction between SOL concepts and TTC concepts.
Under this SOL Methodology revision,WECC Paths do not have single uniquely monitored
SOLs unless the WECC Path is associated with an established transient or voltage stability
limit;however,WECC Paths that are associated with scheduling will continue to have TTCs.
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Ultimately,much of what has historically been considered an SOL is not considered an SOL
under this SOL Methodology.
Under this SOL Methodology,SOLs are the Facility Ratings,System Voltage Limits,transient
stability limits and voltage stability limits that are used in operations -any of which can be the
most restrictive limit at any point in time pre-or post-Contingency.For example,if an area of
the BES is at no risk of encroaching upon stability or voltage limitations in the pre-or post-
Contingency state,and the most restrictive limitations in that area are pre-or post-
Contingency exceedance of Facility Ratings,then the thermal Facility Ratings in that area are
the most limiting SOLs.Conversely,if an area is not at risk of instability and no Facilities are
approaching their thermal Facility Ratings,but the area is prone to pre-or post-Contingency
low voltage conditions,then the System Voltage Limits in that area are the most limiting SOLs.
Per the NERC definition,TTC is the 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.While it is expected that TTC respect pre-and post-Contingency reliability
limitations associated with Facility Ratings,System Voltage Limits and stability limitations,the
determination and communication of TTC is outside the scope of Peak's SOL Methodology.
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Figure 1 -POTF Basic Principle shown below characterizes the decoupling of TTC and SOL.
POTF Basic Principle
Ratinat/hsOL
Path TTC:SOLS:
Not an SOL Facility Ratings
Respects SOLs
,
Voltage limits
Respects three-phase rating Stabilitylimits
process,commercial issues,These are observed pre-and
contracts,and allocations post-Contingenc)
U O LJ
Figure 1 -POTF Basic Principle
H.Role of WECC Path Ratings
Under the historical Path SOL paradigm,Transfer Capability,scheduling limits,allocations,
commercial considerations and historical reliability assessments performed in years past were
all rolled up into a parameter that is monitored in Real-time operations as an SOL.In the
Western Interconnection,Path SOLs were historically limited by and equal to the WECC Path
Ratings unless studies indicated the need for a lower Path SOL value.While WECC Path
Ratings have a basis in reliability studies performed in the planning horizon,the Path Rating
process and the granted Path Rating exist primarily to safeguard the protection of investments
and to ensure that the reliability impacts of new transmission projects are understood and that
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mitigations are agreed upon by all impacted entities before the transmission project becomes
operational.
This SOL Methodology does not recognize WECC Path Ratings as SOLs.WECC Path
Ratings are determined in the planning horizon per the voluntaryWECC three-phase rating
process.As stated earlier,this SOL Methodology recognizes SOLs to be the Facility Ratings,
System Voltage Limits and stability limitations used in operations.If a WECC Path Rating is
determined to be "stability limited"per the WECC three-phase rating process,this information
can be used by TOPs and the RC to perform further analysis to determine if a stability limit
should be established for use in the Operations Horizon;however,the "stability limited"WECC
Path Rating itself is not automatically considered as a stability limit (SOL)for use in the
Operations Horizon.
I.SOLs Versus Mechanisms to Prevent Limit Exceedance -the Role
of Operating Plans
It is important to distinguish operating practices and strategies from the SOL itself.As stated
above,the SOL is the actual set of Facility Ratings,System Voltage Limits and stability limits
that are to be monitored for the pre-and post-Contingency state.How an entity remains within
these SOLs can vary depending on the planning strategies,operating practices and
mechanisms employed by that entity.For example,one TOP may utilize line outage
distribution factors or other similar calculations as a mechanism to ensure SOLs are not
exceeded,while another may utilize advanced network applications to achieve the same
reliability objective.Regardless of the strategies employed,the Reliability Standards require
that RTAs (per the revised definition of RTA)be performed at least once every 30 minutes to
determine if any SOLs are exceeded.
The TOP and IRO standards portray an operating paradigm where the Operating Plan is the
ultimate mechanism for ensuring operation within SOLs.The NERC Glossary of Terms
defines an Operating Plan as follows:
A document that identifies a group of activities that may be used to achieve some goal.
An Operating Plan may contain Operating Procedures and Operating Processes.A
company-specific system restoration plan that includes an Operating Procedure for
black-starting units,Operating Processes for communicating restoration progress with
other entities,etc.,is an example of an Operating Plan.
When an SOL is being exceeded in Real-time operations,the TOPs,BAs,and RCs are
required to implement mitigating strategies consistent with their Operating Plan(s).Operating
Plans can include specific Operating Procedures or more general Operating Processes.
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Operating Plans include both pre-and post-Contingency mitigation plans/strategies.Pre-
Contingency mitigation plans/strategies are actions that are implemented before the
Contingency occurs to prevent the potential negative impacts on reliability associated with the
Contingency.Post-Contingency mitigation plans/strategies are actions that are implemented
after the Contingency occurs to bring the system back within limits.Operating Plans contain
details to include appropriate timelines to escalate the level of mitigating plans/strategies to
ensure BES performance is maintained as per approved FAC-011-3,Requirement R2.
Operating Plan(s)must include the appropriate time element to return the system to within
acceptable Normal and Emergency (short-term)Ratings to prevent post-Contingency
equipment damage and/or non-localized Cascading outages.
J.The Role of Nomograms and TTC in Operations Reliability
Nomograms are created ahead of time to predict a safe region whereby operating inside the
region would be expected to result in acceptable pre-and post-Contingency system
performance.They are a mechanism to describe interaction between elements or Paths with
the objective of ensuring that the system is operated in a safe and reliable state while the use
of related elements or Paths are simultaneously maximized.Nomograms may be used to
provide System Operators with helpful guidance as part of an Operating Plan;however,they
are not considered to be SOLs unless the nomogram represents a region of stability (i.e.,the
nomogram defines a stability limit).
Similarly,TTC is not an SOL,and thus it is not an operating parameter.However,if a TOP so
chooses,the TOP may utilize TTC (and Transfer Capability concepts)as part of an Operating
Plan as a means by which to achieve acceptable pre-or post-Contingency performance and
thus to prevent SOL exceedances.
Note that exceeding a TTC value in Real-time operations does not constitute SOL
exceedance.For example,if TTC for a WECC Path is determined to be 1200 MW in the north-
to-south direction,and Real-time flow on that Path reaches 1300 MW,it cannot be concluded
that an SOL is being exceeded.When Path flow is at 1300 MW,and RTAs indicate that no
unacceptable pre-or post-Contingency performance is occurring,an SOL is not being
exceeded.Conversely,if at a Path flow of 1000 MW,RTAs indicate that unacceptable pre-or
post-Contingency performance is occurring,an SOL is being exceeded.If the SOL
exceedance is occurring because of heavy transfers on the WECC Path,and Operating Plan
for that SOL exceedance includes decreasing north-to-south flow on the WECC Path,or it is
determined in real-time that decreasing north-to-south flow on the WECC Path is effective in
mitigating the SOL,then it is expected that those mitigation measures be taken to address the
SOL exceedance.
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While TTCs and nomograms may serve as valuable mechanisms to prevent and/or mitigate
SOL exceedances as part of an Operating Plan,these mechanisms are not a substitute for
performing RTAs and do not absolve the TOP or the RC of its obligation to perform RTAs to
identify SOL exceedance per the TOP and IRO Reliability Standards.
K.Path Operators,Path Operations,and TOP-007-WECC-1a
The SOL Methodology does not recognize the "Path Operator"as an operational entity.
Consistent with the NERC Reliability Standards,the SOL Methodology recognizes TOPs and
the RC as being responsible for operating within SOLs,though BAs may have a role in the
Operating Plan to prevent or mitigate SOL exceedances.If,for example,heavy Path or
interface flow is determined to be the cause of an SOL exceedance,it is expected that steps
be taken by the associated TOPs and BAs per the pertinent Operating Plan to alleviate the
condition by reducing flow on the Path or interface.The Operating Plans are expected to refer
to the TOPs,BAs and the RC applicable to the Operating Plan.
While Peak will continue to monitor WECC Path flow relative to WECC Path TTC values for
situational awareness purposes,Peak does not acknowledge the TTC as a SOL and does not
require operation within TTC values or WECC Path Ratings.Peak monitors the entire BES for
SOL exceedance (as described in the SOL Methodology)and implements Operating Plans as
required to address instances of SOL exceedances as determined by RTAs.
TOP-007-WECC-1a
The remainder of Section K is effective until the retirement of TOP-007-WECC-1a is
effective.
Until TOP-007-WECC-1a is retired,the 40 Paths in the list of "Major WECC Transfer Paths
in the Bulk Electric System"will continue to have Path SOLs as they have had historically.
SOLs for these 40 Paths should be established to respect pre-and post-Contingency
acceptable performance for Facility Ratings,System Voltage Limits,stability limitations and
WECC Path Ratings,as has been done historically2.The entity that currently establishes the
SOL for a given Path is responsible for continuing to establish and communicate that Path
SOL until the retirement of TOP-007-WECC-1a is effective.
2 Anticipated emergency conditions may warrant operating to an SOL that is higher than the WECC Path
Rating.Planning for such anticipated emergency conditions must be coordinated with the RC and
impacted TOPs prior to day-ahead operations to ensure reliability issues are addressed and related
Operating Plans are developed.
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This provision applies only to the 40 Paths in the list of "Major WECC Transfer Paths in the
Bulk Electric System."These 40 Paths are the only Paths for which Peak will accept a Path
SOL in the historical and traditional sense (i.e.,for non-stability related issues).
Upon the effective date of the retirement of TOP-007-WECC-1a,the SOL Methodology will
no longer require SOLs for the 40 Paths in the list of "Major WECC Transfer Paths in the
Bulk Electric System"to be established and communicated to Peak (unless the Path is
associated with a stability limitation).
TOP-007-WECC-1a Path SOL Establishment and Communication Requirements
In summary,the following requirements apply while TOP-007-WECC-1a is effective:
1.Each TOP that currently establishes SOLs for Paths contained in the list of "Major
WECC Transfer Paths in the Bulk Electric System"shall continue to establish SOLs
for those Paths.
2.Each TOP that establishes SOLs for Paths contained in the list of "Major WECC
Transfer Paths in the Bulk Electric System"per Item 1 above shall continue to
communicate the Path SOL per historical communication protocols.
L.Acceptable System Performance
In the Peak RC Area,the BES is expected to be operated such that acceptable system
performance is being achieved in both the pre-and post-Contingency state.This section
describes acceptable system performance for the pre-and post-Contingency state [NERC
Standard FAC-011-3 R2].
It is not the intent of this SOL Methodology to require more stringent BES performance than
that stipulated in the prevailing NERC Transmission Planning (TPL)Reliability Standards and
WECC TPL criteria;however,the SOL Methodology may prescribe specific performance
criteria where the corresponding performance criteria in planning is non-specific.
1.Pre-Contingency:Acceptable system performance for the pre-Contingency state in
the Operations Horizon is characterized by the following3 [NERC Standard FAC-011-
3 R2.1]:
a.The BES shall demonstrate transient,dynamic and voltage stability.
3 Note that these pre-and post-Contingency performance requirements are applicable to BES Facilities.
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b.All Facilities shall be within their normal Facility Ratings and thermal limits.
(Refer to Figure 2 -SOL Performance Summary for Facility Ratings below.)
c.All Facilities shall be within their normal System Voltage Limits.
d.All Facilities shall be within their stability limits.
2.Post-Contingency (for single Contingencies listed in "3"below):Acceptable system
performance for the post-Contingency state for single Contingencies in the
Operations Horizon is characterized by the following (NERC Standard FAC-011-3R2.2)3
a.The BES shall demonstrate transient,dynamic and voltage stability.
b.All Facilities shall be within their emergency Facility Ratings and thermal
limits.(Refer to Figure 2 -SOL Performance Summary for Facility Ratings
below.)
c.All Facilities shall be within their emergency System Voltage Limits.
d.All Facilities shall be within their stability limits.
e.Cascading or uncontrolled separation shall not occur.
3.The single Contingencies referenced in "2"above include the following4:
a.Single-line-to-ground (SLG)or three-phase Fault (whichever is more severe),
with Normal Clearing,on any Faulted generator,line,transformer or shunt
device [NERC Standard FAC-011-3 R2.2.1].
b.Loss of any generator,line,transformer,or shunt device without a Fault
[NERC Standard FAC-011-3 R2.2.2].
c.Single pole block,with Normal Clearing,in a monopolar or bipolar high
voltage direct current system [NERC Standard FAC-011-3 R2.2.3].
Note that these Contingencies are reflective of the single P1 Contingency type
described in Table 1 -Steady State &Stability Performance Planning Events found
in NERC Reliability Standard TPL-001-4.Henceforth,these Contingencies will be
referenced as single P1 Contingencies.Also note that the initial state for the P1
Contingency type in TPL-001-4 is "normal system,"whereas the initial state for the
4 The Contingencies identified in items (a)through (c)are the minimum Contingencies that must be
studied but are not necessarily the only Contingencies that should be studied.
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P1 Contingency term used in this document is the actual or expected configuration of
the system in the Operations Horizon,which is generally not "normal system,"i.e.,
multiple Facilities may be out of service.
4.Acceptable system performance for credible multiple Contingencies (MC)are
addressed in the next section.
5.The following Contingencies at a minimum are applicable for TOP assessments
within the Operations Horizon:
a.Single P1 Contingencies internal to the TOP Area.
b.Credible MCs internal to the TOP Area.
c.Any single P1 Contingencies and Credible MCs external to the TOP Area that
are known to or may impact the TOP Area or system under study,as
determined by the TOP.TOPs are responsible for determining whether
Contingencies outside their TOP Area impacts them and for determining the
external modeling necessary to support the evaluation of those
Contingencies in their assessments.
6.Acceptable System Response:In determining the system's response to a single P1
Contingency,the following actions shall be acceptable [NERC Standard FAC-011-3
R2.3]:
a.Planned or controlled interruption of electric supply to radial customers or
some local network customers connected to or supplied by the faulted Facility
or by the affected area [NERC Standard FAC-011-3 R2.3.1].
b.Interruption of other network customers [NERC Standard FAC-011-3 R2.3.2]:
i.Only if the system has already been adjusted,or is being adjusted,
following at least one prior outage,or
ii.If the Real-time operating conditions are more adverse than
anticipated in the corresponding studies.
iii.System reconfiguration through manual or automatic control or
protection actions [NERC Standard FAC-011-3 R2.3.3].Adequate
time must be allowed for manual reconfiguration actions.
7.To prepare for the next Contingency,system adjustments may be made,including
changes to generation,uses of the transmission system,and the transmission
system topology [NERC Standard FAC-011-3 R2.4].
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Figure 2 -SOL Performance Summary for Facility Ratings provides an example of acceptable
pre-and post-Contingency performance for a sample set of Facility Ratings.The Facility
Ratings shown in the example are selected for illustration purposes only.
SOL Performance Summary
Pre-Contingency flow in this range is not acceptable.
·Post-Contingency flow in this range is not acceptable;however,pre-
Contingency load shed may not be necessary or appropriate.
Operating Plans and mitigationstrategies should address load shed
950 MVA (15 min rating)-as necessary to ensure impact is localized.
Pre-Contingency flow in this range for longer than 15 min is not
acceptable.
Post-Contingency flow in this range is acceptable,provided that,if the
single Contingency were to occur in Real-timeoperations,flow can be
reduced to below acceptable limits within 15 minutes.If this reduction
900 MVA (4 hr rating)cannot be achieved within 15 minutes,pre-Contingency actions must
be taken to reduce post-Contingency flow below 900 MVA.
·Pre-Contingency flow in t ange fo onger than 4 hours is not
acceptable.
Post-Contingency flow in this range is acceptable provided that,if the
Contingency were to occur in Real-time operations,flow can be
800 MVA (24 hr rating)----..reduced to below 800 MVA within 4 hours.
Pre-and post-Contingency flow in this range represents
acceptable system performance.
O MVA
Note 1:Pre-Contingency flow is the actual MVA flow observed on the Facility through Real-timeoperations monitoring.
Note 2:Post-Contingency flow is the calculated MVAflow expected to occur on the Facility in response to a single Contingency
as indicated by Real-timeAssessments.
Note 3:24 hour,4 hour,15 minuteratings are provided as an example for illustration purposes and may be different based on
individual TO Rating methodologies.
Figure 2 -SOL Performance Summaryfor Facility Ratings
M.Multiple Contingencies (MC)in Operations
This section of the SOL Methodology describes how MCs are to be addressed in the
Operations Horizon [NERC Standard FAC-011-3 R3.2,3.3,and 3.3.1].
Background -Determininq an MC's Credibility for the Operations Horizon
MC management presents a significant challenge to engineers and System Operators.The
primary challenge associated with managing MCs is the concept of MC "credibility."PCs and
TPs are required by the TPL standards to assess a variety of MCs and to develop Corrective
Action Plans when the system does not perform acceptably with regard to those Contingency
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event categories.The TPL standards do not provide PCs and TPs the latitude of determining
which MCs are considered credible in the planning horizon.Rather,the MCs to be assessed
are spelled out,and the performance requirements and expectations for those MCs are clear.
However,in the Operations Horizon,the concept of risk management comes into play with
regard to MC considerations.In the Operations Horizon,MC credibility is a function of the
plausibility (believability)of an event and the likelihood that it will occur.Ultimately,operators
and engineers in the Operations Horizon need to decide whether or not the system needs to
be operated to prevent the impacts of a particular MC event at any given time.It is recognized
that TOPs in the Western Interconnection have a wide variety of unique operational issues
and unique risk profiles that may result in different needs with regard to managing MCs in
operations.The SOL Methodology presents a cohesive and unified approach to MC
management while at the same time affording TOPs the flexibility to address their unique
challenges and risk profiles.
Two Types of Credible MCs in the Operations Horizon
Credible MCs for the Operations Horizon can be broadly considered to fall into two categories
-those that are "Always Credible"and those that are "Conditionally Credible."
Always Credible MCs -There are MCs that,based on historical performance and
TOP risk assessments,have a sufficiently high degree of likelihood of occurrence
such that the TOP determines that the MC should be protected against in all phases
of the operations planning process and in Real-time operations.The credibility of
these MCs does not change based on observable operating conditions,but rather
their credibility is static based on TOP performance and risk assessments.
ConditionallyCredible MCs -On the other hand,there are MCs whose credibility
is a function of observable system conditions.For these,the MC is credible only
when the observable system conditions are present.When the observable system
conditions are not present,the MC is not credible.Examples of this type of MC are
those that become credible upon known and observable threats like fires,or adverse
weather risks such as flooding,icing,tornados.Similarly,when a breaker has a low-
gas alarm,this condition can pose a risk that the breaker may not operate as
anticipated should it be called upon to clear a Fault.In such cases,System
Operators might operate the system to account for the possible failure of this breaker
during those conditions.Such Conditionally Credible MCs present operators and
engineers with the challenge of determining which of these,if any,should be pre-
identified for development of a standing MC-specific Operating Plan that can be
applied should the conditions arise that would render the MC as being credible in
operations.The SOL Methodology provides TOPs with the flexibility to optionally pre-
identify potential risks associated with Conditionally Credible MCs and to develop
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standing Operating Plans ahead of time for those MCs should the associated
conditions occur in Real-time operations.
TOPs should generally consider the following MC types when determining any Always
Credible MCs for operations.These Contingency types serve as a starting point for the
internal risk assessment for determining Always Credible MCs.Upon review of these MC
types,the TOP should determine which of these,if any,are designated as Always Credible
MCs for operations:
1.Bus Fault Contingencies (though this is listed as a P2 single Contingency in TPL-
001-4,it is considered a lower-probability,higher-impact event in operations and
therefore is considered along with other MCs for both credibility determination and
performance requirements)
2.Stuck breaker Contingencies (reflective of a P4 Contingency in TPL-001-4)
3.Relay failure Contingencies where there is no redundant relaying (reflective of a P5
Contingency in TPL-001-4)
4.Common structure Contingencies (reflective of a P7 Contingency in TPL-001-4)
5.Any of the MCs that have been determined by its PC to result in stability limits
(provided to the RC per FAC-014-2 R6)[NERC Standard FAC-011-3 R3.3.1]
Note that N-1-1 Contingency types (reflective of P3 and P6 Contingencies in TPL-001-4)are
not under consideration under the auspices of MC credibility.Specific combinations of two
overlapping single Contingencies is not an issue of credibility or non-credibility.For such
combinations of single Contingencies,it is a matter of knowing which combinations to be
prepared for based on known issues with those specific combinations.Such operational risks
are expected to be addressed through Operating Plans as these risks are identified.
Reference the IROL Establishment section of the SOL Methodology for more information on
N-1-1 risk assessment.
Requirementsfor Identifyinq Always Credible MCs in Operations
6.MCs that are considered Always Credible for operations include those that are
determined to have static credibility through all phases of the operations planning
process (seasonal and other special studies,outage coordination assessments,and
Operational Planning Analyses)and in Real-time operations (including Real-time
Assessments).These MCs are not a function of observable operating conditions.
7.TOPs shall document the list of Always Credible MCs per the RC instructions posted
on Peak's website.Note that the RC instructions require each Always Credible MC to
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be accompanied by a rationale for its credibility.The list of Always Credible MCs in
operations resides in the secured area of the peakrc.org website and is accessible
by TOPs and BAs that have access to the website.If a TOP has no Always Credible
MCs identified,the TOP should indicate that to the RC.
8.When developing the list of Always Credible MCs for operations,TOPs are expected
to perform an internal evaluation of historical MC performance and an internal risk
assessment to determine the MCs internal to their TOP Area that are considered
Always Credible for operations based on factors and issues that are unique to their
TOP Area.
9.It is the primary responsibility of the TOP in whose TOP Area the MC Facilities reside
to determine MC credibility.However,because the RC is the highest authority in the
Interconnection,the RC has the authority to determine an MC's credibility that
supersedes a TOP's designation.Should the RC exercise such authority,the RC
shall perform an evaluation of historical MC performance and a risk assessment
based on the factors and issues driving the RC to supersede the TOP's
determination,and the RC shall share this information with impacted TOPs.
10.When a MC terminates in different TOP Areas,the TOPs are expected to collaborate
and agree on the MC credibility.
11.If an impacted TOP challenges or disagrees with a TOP's decision or rationale for a
MC's credibility,or if TOPs cannot agree on the credibility of the MC that impacts
their TOP area,the TOPs involved are expected to coordinate with the RC to reach a
resolution.If agreement/resolution cannot be achieved through collaboration,the RC
has the authority to make final determination of the MC credibility.In its final
determination,the RC is expected to coordinate with the applicable PC(s)and to
consider how the system was planned,built and is intended to be operated.The RC
will document the final resolution.
12.Contingencies more severe than bus Fault Contingencies,stuck breaker
Contingencies,relay failure Contingencies and common structure Contingencies are
considered to be extreme events and are generally not under consideration as
Always Credible MCs for the Operations Horizon;however,exceptions may exist due
to the severe and widespread adverse consequences of the MC.If there are any
extreme Contingencies that the TOP or the RC determines to be Always Credible for
operations,Peak and the impacted TOPs are expected to collaborate to determine
how those extreme events are to be addressed in operations planning and in Real-
time operations.
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AddressinqConditionallyCredible MCs in Operations
13.Conditionally Credible MCs are not required to be pre-identified or included along
with the list of Always Credible MCs.However,if the TOP optionally pre-identifies
any Conditionally Credible MCs and creates a standing Operating Plan for that MC,
the TOP shall provide that Operating Plan to Peak per RC instructions for awareness
purposes.If such pre-identified Operating Plans impact or involve other TOPs,then
the Operating Plan should be developed in collaboration with the impactedlinvolved
TOPs and communicated to those TOPs.
14.Conditionally Credible MCs become credible when the Conditionally Credible MC
poses a risk to reliability due to a known,foreseeable or observable threat.The TOP
in whose TOP Area the MC Facilities reside is responsible for determining when a
Conditionally Credible MC becomes credible and when it ceases to be credible.
15.When a Conditionally Credible MC becomes credible,the TOP in whose TOP Area
the MC Facilities reside must notify the RC and other TOPs known or expected to be
impacted by the MC.The TOP in whose TOP Area the MC Facilities reside must
collaborate with the RC and impacted TOPs to create and implement an Operating
Plan (or to implement a pre-determined Operating Plan)to address the known and
observable risk associated with the Conditionally Credible MC.
16.Impacted TOPs and the RC are expected to include the Conditionally Credible MCs
in their respective studies while the Conditionally Credible MC is credible.
17.When Conditionally Credible MCs become credible and the MC impacts multiple
TOPs,the RC will collaborate with impacted TOPs to ensure that the MC is being
addressed in a coordinated manner.
Performance Requirementsfor Always Credible and ApplicableConditionallyCredible
MCs
18.The MC shall not result in:
a.System-wide instability
b.Cascading
c.Uncontrolled separation
19.It is acceptable for Always Credible and applicable Conditionally Credible MCs to
result in exceedance of emergency Facility Ratings and emergency voltage limits,
provided these SOL exceedances do not result in the conditions described in item 18
above.The Cascading test described in the Instability,Cascading,Uncontrolled
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Separation and IROLs section of the SOL Methodology applies when determining
potential Cascading.
20.Always Credible and applicable Conditionally Credible MCs are expected to meet
these performance requirements in all phases of assessments in the Operations
Horizon -seasonal planning,special studies,outage coordination studies,OPAs and
RTAs.
21.A TOP may choose to adopt more stringent performance requirements for Always
Credible or applicable Conditionally Credible MCs;however,a TOP's self-imposed,
more stringent performance requirements may not require neighboringlimpacted
TOPs to accommodate these more stringent requirements.TOPs are at liberty to
agree on more stringent performance requirements for credible MCs.
22.Peak will neither operate -nor require that TOPs operate -to more stringent criteria
than the criteria specified in item 18 above.
Requirementsfor the Treatment of Credible MCs in the Operations Horizon
23.The RC must include Always Credible MCs in RC assessments (seasonal
assessments,special studies,outage coordination studies,OPAs,RTAs).The RC
must include Conditionally Credible MCs in RC assessments while the MC is
credible.
24.TOPs must include their own Always Credible MCs in TOP assessments (seasonal
assessments,special studies,outage coordination studies,OPAs,RTAs).The TOP
must include its own Conditionally Credible MCs in TOP assessments while the MC
is credible.
25.If TOP seasonal assessments,special studies,outage coordination studies or OPAs
are validated to indicate that an Always Credible or applicable Conditionally Credible
MC does not meet MC performance requirements described in the SOL
Methodology,the TOP must develop an Operating Plan to provide for acceptable
performance for the MC.It is possible that an IROL may need to be established to
address the reliability risk.Reference the IROL Establishment section of the SOL
Methodology for more information.Similarly,if TOP RTAs are validated to indicate
that a credible MC does not meet MC performance requirements described in the
SOL Methodology,the TOP must implement an Operating Plan to mitigate the
unacceptable system performance for the credible MC.
26.Peak includes credible MCs in RC assessments (both Always Credible MCs and any
applicable Conditionally Credible MCs that are communicated to the RC)and
evaluates those MCs against the MC performance requirements.Peak applies the
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Cascading test as described in the section entitled Instability,Cascading,
Uncontrolled Separation and IROLs when determining potential Cascading.Peak
does not evaluate credible MCs against more stringent performance requirements.If
Peak's special studies,outage coordination studies or OPAs are validated to indicate
that a credible MC does not meet MC performance requirements,an Operating Plan
must be developed to provide for acceptable performance for the credible MC.
Similarly,if Peak's RTAs are validated to indicate that a credible MC does not meet
MC performance requirements described in the SOL Methodology,an Operating
Plan must be implemented to mitigate the unacceptable system performance for the
credible MC.Peak does not include non-credible MCs in RC assessments.
27.If an MC is not declared as Always Credible by the TOP in whose TOP Area the MC
Facilities reside and is not posted on the peakrc.org website,then the MC is not
required to be honored in the Operations Horizon (seasonal assessments,special
studies,outage coordination assessments,OPAs,RTAs).Note that Conditionally
Credible MCs that become credible in operations are addressed separately.
28.Note that not "all"Contingencies within a TOP Area (single P1 Contingencies or
credible MCs)are expected to be included in certain types of analyses.For example,
time-domain,PVlQV and transfer studies are not conducive to analyzing as many
Contingencies as can be done in steady-state Contingency Analyses performed as
part of a power flow.For studies such as time-domain analyses and PVlQV
analyses,TOPs and the RC are expected to include those Contingencies that are
the most impactful to the situation based on experience,engineering judgment and
historical analysis.
29.If a TOP determines that an MC in its TOP Area is non-credible,yet a
neighboringlimpacted TOP desires to include that non-credible MC in its
assessments,the neighboringlimpacted TOP may do so;however,the
neighboringlimpacted TOP cannot require other TOPs to address reliability issues
related to the non-credible MC and cannot require any other TOP to honor that MC in
operations or in the development or implementation of Operating Plans.
N.SOL Exceedance
SOL exceedance occurs when acceptable system performance requirements as described in
approved FAC-011-3 are not being met,be it in seasonal planning studies,special studies,
outage studies,OPAs or RTAs.In other words,unacceptable system performance equates to
SOL exceedance.This SOL Methodology considers SOL exceedance to be a condition
characterized by any of the following:
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1.Actuallpre-Contingency flow on a Facility is above the Normal Rating
2.Calculated post-Contingency flow on a Facility is above the highest Emergency
Rating
3.Actuallpre-Contingency bus voltage is outside normal System Voltage Limits
4.Calculated post-Contingency bus voltage is outside emergency System Voltage
Limits
5.Operating parameters indicate a Contingency could result in instability
O.Allowed Uses of Automatic Mitigation Schemes in the Operations
Horizon
This section describes how the SOL Methodology addresses the allowed uses of automatic
mitigation schemes in the Operations Horizon,both those that shed load as part of the
scheme as well as those that do not.This document is applicable to Remedial Action
Schemes (RAS)and other non-RAS schemes that automatically take mitigation action in
response to system conditions or Contingency events [NERC Standard FAC-011-3 R3.5].
The revised NERC definition of RAS has an effective date of April 1,2017.As a result,some
automatic schemes that were not previously considered a RAS may be considered a RAS
under the new definition,and vice versa.Item "e"in the RAS definition excludes schemes
applied to an Element for non-Fault conditions that remove that Element from service to
protect it from damage due to overload conditions.Such schemes,while not considered a
RAS,are included here within the broader context of automatic mitigation schemes.
The following items describe the allowed use of automatic mitigation schemes in the
Operations Horizon,including both non-load-shed automatic schemes and load-shed
automatic schemes:
1.If a TOP relies upon an automatic scheme for providing acceptable performance for
single Contingencies or credible MCs,then the actions of the automatic scheme
must be modeled in assessment tools or otherwise included in the TOP's analysis
and the RC's analysis as applicable.
2.If at any time OPAs or other prior analyses indicate that the automatic scheme either
fails to mitigate the reliability issue,potentially causes other reliability issues or could
result in a more significant reliability risk,or if the automatic scheme is expected to
be unavailable,the TOP must develop an Operating Plan in coordination with
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impacted TOPs and the RC,that contains pre-Contingency mitigation actions to
address the reliability issue.
3.If at any time RTAs indicate that the automatic scheme either fails to mitigate the
reliability issue,potentially causes other reliability issues or could result in a more
significant reliability risk,or if the automatic scheme is unavailable,the TOP must
initiate an Operating Plan in coordination with impacted TOPs and the RC,to take
pre-Contingency mitigation actions to address the reliability issue.
4.Automatic schemes that have a single point of failure may not be utilized to prevent
System instability,Cascading or uncontrolled separation from occurring in response
to single P1 Contingencies or credible MCs.If any TOP seeks an exception,the TOP
shall coordinate with the RC and request to be granted an exception until the
necessary redundancies can be put in place and the automatic scheme classification
is updated per the applicable standard or regional criteria.Exceptions may be made
only for conditions that would otherwise require pre-Contingency load shedding.If
operational situations arise where an automatic scheme that has a single point of
failure must be relied upon to avoid pre-Contingency load shedding,such conditions
must be coordinated and approved for use by the RC.
5.If an automatic scheme is relied upon to prevent System instability,Cascading or
uncontrolled separation in the transient or post-transient timeframe,the TOP studies
must assess those timeframes to ensure that the automatic action occurs in time to
prevent System instability,Cascading or uncontrolled separation.
6.Several automatic schemes are intended and designed to address certain non-
credible MCs (including extreme event Contingencies).In the Operations Horizon,
these schemes are allowed to be relied upon to meet their intended design
objectives for those non-credible and extreme event Contingencies;however,the
SOL Methodology does not require assessment of -and therefore,determination of
acceptable performance for -non-credible and extreme event Contingencies in the
Operations Horizon.
Requirements Specific to Non-Load-Shed Automatic Schemes
Non-load-shed schemes include those that do not shed load as part of the mitigation action of
that scheme.Examples of such schemes include generation drop schemes and transmission
reconfiguration schemes.
7.Non-load-shed automatic schemes are not as restricted in their use as are load-shed
automatic schemes.Accordingly,use of non-load-shed automatic schemes is
allowed for the same conditions where the use of load-shed automatic schemes is
allowed.
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8.Non-load-shed schemes may be used as an acceptable automatic post-Contingency
mitigation action,provided the general requirements listed in items 1-6 above are
met.
9.If a TOP intends to use a non-load-shed scheme in a manner for which the scheme
was not intended and designed,and that intended use impacts other TOPs,the TOP
must coordinate with impacted TOPs prior to reliance on that scheme.
Requirements Specific to Load-Shed Automatic Schemes
Load-shed schemes include any scheme that automatically sheds load in response to
Contingency events.Such schemes include,but are not limited to,load-shed RAS,
Underfrequency Load Shedding (UFLS)schemes,Undervoltage Load Shedding (UVLS)
schemes (including UVLS Programs)or other non-RAS schemes that automatically shed load
in response to Contingency events.Note that the term "UVLS"refers to distributed UVLS and
includes UVLS Programs as defined in the NERC Glossary of Terms.RAS or other relay
schemes that monitor transmission voltages and drop load based on those voltages are not
considered as a UVLS.
Definition of Undervoltage Load Shedding Program from the NERC Glossary of Terms:
An automatic load shedding program,consisting of distributed relays and controls,used
to mitigate undervoltage conditions impacting the Bulk Electric System (BES),leading to
voltage instability,voltage collapse,or Cascading.Centrally controlled undervoltage-
based load shedding is not included.
In principle,the use of load-shed schemes in the Operations Horizon must take into
consideration how the scheme was intended and designed to be utilized.
The following items describe the allowed use of load-shed schemes in the Operations
Horizon:
10.In general,load-shed schemes should be used and relied upon for the
conditionslevents for which the load-shed scheme was intentionally designed.
Though there may be scenarios where it is appropriate to use or rely upon load-shed
schemes to address Contingency events for which the load-shed scheme was not
designed,such instances should be minimized and should be thoroughly
investigated and studied in the operations planning timeframe to ensure that reliance
on these schemes is reliable,prudent,consistent with sound engineering judgment
and utility practice,and reflects appropriate risk management principles.
11.There may be conditions where the operational consequences of some load-shed
schemes are such that TOPs in collaboration with the RC may choose to implement
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an Operating Plan that prevents the load-shed scheme from triggering for a given
operating condition or Contingency event.
12.Some load-shed schemes are intended and designed to address certain credible
MCs.If a load-shed scheme is intended and designed to address a specific credible
MC,then the load-shed scheme is allowed to support economic operations and is
allowed for consideration in the Operations Horizon,for:
a.Assessing acceptable post-Contingency system performance for those
Contingencies
b.Determining whether or not a stability limit or an IROL needs to be
established
c.Calculating the value of the stability limit or the IROL,once it has been
determined that there is a need to establish a stability limit or an IROL
13.Load-shed schemes may be relied upon and utilized in operations for single P1
Contingencies if the scheme's impact is limited to a small amount of load in the local
network area.However,load-shed schemes may not be relied upon or utilized in
operations for single P1 Contingencies to support economic operations.6
14.There are times when a planned or forced outage of a Facility causes a MC in
planning to become a single P1 Contingency in operations6.When this type of
6 The intent is to,if at all possible,limit reliance on such load-shed schemes to those that were designed
and implemented per the allowances specified in Table 1 of TPL-001-4 for P1 Contingencies.While Table
1 TPL-001-4 indicates that Non-Consequential Load Loss is not allowed for single P1 Contingencies,the
table includes footnote 12 which states,"An objective of the planning process is to minimize the likelihood
and magnitude of Non-Consequential Load Loss following planning events.In limited circumstances,
Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES
performance requirements are met.However,when Non-Consequential Load Loss is utilized under
footnote 12 within the Near-Term Transmission Planning Horizon to address BES performance
requirements,such interruption is limited to circumstances where the Non-Consequential Load Loss
meets the conditions shown in Attachment 1.In no case can the planned Non-Consequential Load Loss
under footnote 12 exceed 75 MW for US registered entities.The amount of planned Non-Consequential
Load Loss for a non-US Registered Entity should be implemented in a manner that is consistent with,or
under the direction of,the applicable governmental authority or its agency in the non-USjurisdiction."
6 Example:A UVLS Program is designed in the planning horizon to prevent a P7 common structure
Contingency from resulting in instability.The structure carries two transmission lines.One of these two
lines is removed from service on a planned or forced outage.From an operations perspective,the loss of
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scenario occurs for MCs (or for certain P2 Contingencies that remove multiple
Elements)for which a load-shed scheme was designed,the scheme can be relied
upon and utilized in operations according to the following:
a.When a forced or urgenti outage of a Facility causes a MC in planning to
become a single P1 Contingency in operations,the load-shed scheme can be
relied upon to provide for acceptable system performance for the next single
P1 Contingency;however,System Operators shall take appropriate action up
to,but not necessarily including load shedding,to (if at all possible),re-
position the system in response to the forced or urgent outage such that the
load-shed scheme is not required to provide for acceptable system
performance for the next single P1 Contingency6.In such conditions,Real-
time studies,operationslengineering judgment and the operational
consequences of the load-shed scheme should be considered in the overall
risk management exercise when determining the appropriate course of
action.
b.When a planned outage of a Facility causes a MC in planning (for which a
load-shed scheme was designed)to become an N-1 Contingency in
operations,TOPs shall develop an outage-specific Operating Plan to take
appropriate action up to,but not including load shedding,to (if at all possible)
pre-position the system such that the load-shed scheme is not required to
provide for acceptable system performance for the next single P1
Contingency for the duration of the planned outage?.In planned outage
scenarios,load-shed schemes are not allowed to be used to support
economic operations for the next worst single P1 Contingency.If at all
possible,reliance on load-shed schemes for single P1 Contingencies during
planned outages should be limited to addressing local area thermal or voltage
issues.Any planned outage that requires reliance on load-shed schemes to
prevent instability,Cascading or uncontrolled separation during planned
outages for the next single P1 Contingency will be allowed only upon the
express review and approval by the RC.
the remaining line now represents an N-1 Contingency during the period of time that the outage of the
other line is in effect.
7 Reference IRO-017-1 Outage Coordination Process for description of forced and urgent outage types.
6 Appropriate actions may or may not include sectionalizing.If sectionalizing places more load at risk,
then reliance on load-shed scheme is acceptable if the scheme was designed for the intended purpose.
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i.If at all possible,planned outages should be scheduled for a time
when system conditions are such that a load-shed scheme is not
necessary to provide for acceptable system performance for the next
single P1 Contingency during the planned outage.
ii.If it is not possible to schedule the planned outage according to item
i),and reliance on load-shed scheme cannot be avoided for the next
worst single P1 Contingency during the planned outage,the load-
shed scheme action must be simulated and studied in TOP
assessments and in RC assessments as applicable,and those
studies must demonstrate that the load-shed scheme action provides
for acceptable post-Contingency system performance.
A summary table of key aspects of the allowed uses of automatic mitigation schemes in the
Operations Horizon is provided in Appendix C.
P.Coordination Responsibilities
It is important that TOPs collaborate and coordinate with one another when determining
Always Credible MCs and when establishing each of the three types of SOLs (Facility Ratings,
System Voltage Limits and stability limitations).Because inadequate collaboration and
coordination can result in adverse consequences for the reliability of the BES,TOPs should
take deliberate steps to proactively work with neighboring or impacted entities to ensure that
Always Credible MCs and SOLs are coordinated prior to submission to Peak.
For example,when establishing Facility Ratings for use in operations,TOPs are expected to
coordinate with their respective TOs and with adjacent TOPs to ensure that Facility Ratings
are coordinated.Similarly,when establishing System Voltage Limits,TOPs are expected to
work with TOs and adjacent or impacted TOPs to establish System Voltage Limits that provide
for reliable and orderly operations.
The lack of coordination can have unintended operational or reliability consequences that can
be avoided through proper coordination executed in the spirit of being a good neighbor.
If TOPs are unable to reach a resolution on matters related to TOP-to-TOP collaboration and
coordination,the TOPs should consult with Peak to help resolve the issue.
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Q.SOLs Used in the Operations Horizon
System Operating Limits used in the Operations Horizon include Facility Ratings,System
Voltage Limits and stability limitations.This section describes each of these three types of
SOLs.
Facility Ratings
This section focuses on Facility Ratings and describes how Facility Ratings are to be
established and communicated to the RC.
SOLs shall not exceed associated Facility Ratings [NERC Standard FAC-011-3 R1.2].More
specifically,Facility Ratings are SOLs,and any exceedances of these SOLs should be
prevented and mitigated per the applicable TOP and IRO NERC Reliability Standards.
Pursuant to FAC-008-3,each Transmission Owner (TO)and Generation Owner (GO)is
required to establish Facility Ratings consistent with their corresponding Facility Ratings
Methodology.Per FAC-008-3,these Facility Ratings are required to include Normal Ratings
and Emergency Ratings.While Facility Ratings originate from the TO and the GO,it is the
TOP that determines which of those TOlGO-provided Facility Ratings will ultimately be used in
operations.
It is important for reliability that the RC and the TOPs within the RC Area use the same set of
Facility Ratings in the Operations Horizon,including seasonal planning studies,special
studies,outage coordination studies,Operational Planning Analyses (OPA)and Real-time
Assessments (RTA).
Facility Ratings that are used in the Operations Horizon shall be determined by the TOP in
whose TOP Area the Facilities reside according to the following process:
1.It is the responsibility of the TOP in whose TOP Area the transmission Facilities
reside to obtain the Facility Ratings from the associated TOD.
2.The TOP shall determine which Facility Ratings (both Normal Ratings and
Emergency Ratings,as defined in the NERC Glossary of Terms)provided by the TO
are to be used in the Operations Horizon,expressed in MVA (with an associated kV)
or Amps.Emergency Ratings shall include the time value that is associated with that
9 Generation Facility data,(including Generator Facility Ratings and generator step-up transformer
information)is addressed outside of the SOL Methodology.Reference Peak's IRO-010-3 Data
Specification for required generator data.
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Emergency Rating.For example,a 2-hour 300 MVA rating,or a 30-minute 500 MVA
rating.
3.It is the responsibility of the TOPs to agree on the Facility Ratings of Facilities that
are operated by more than one TOP or Facilities that connect adjacent TOPs.If the
TOPs cannot agree,the most limiting Facility Rating will apply as a default.
4.For any given Facility,Peak Reliability analysis tools are able to model three Facility
Ratings for any given season -one Normal Rating and two Emergency Ratings:
a.Normal Rating (NORM)
b.Emergency Rating #1 (EMER #1)
c.Emergency Rating #2 (EMER #2)
5.If,for a given Facility,the TOP uses only one Emergency Rating in the Operations
Horizon,Peak will use that Facility Rating in both the EMER #1 and the EMER #2
database field.If,for a given Facility,the TOP does not use an Emergency Rating
and only uses a single Facility Rating value for the Facility,Peak will use that value
in the NORM,EMER #1,and EMER #2 database fields.
6.If,for a given Facility,the TOP uses more than three Facility Ratings in its analysis
tools,Peak will implement a subset of these Facility Ratings to its model according to
the following:
a.NORM database field -Peak will use the TOP-provided Normal Rating
b.EMER #1 database field -Peak will use the TOP-provided Emergency
Rating that has the second shortest time value (reference examples below)
c.EMER #2 database field -Peak will use the TOP-provided Emergency
Rating that has the shortest time value,no less than a 15-minute Emergency
Rating (reference examples below)
Example #1:
TOP Ratings Used in Operations Peak Modeled Ratings
Normal Rating =300 MVA Peak modeled NORM Rating
8-hour Emergency Rating =400 MVA
2-hour Emergency Rating =500 MVA
1-hour Emergency Rating =550 MVA Peak modeled EMER #1 Rating
20-min Emergency Rating =600 MVA Peak modeled EMER #2 Rating
Example #2:
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TOP Ratings Used in Operations Peak Modeled Ratings
Normal Rating =300 MVA Peak modeled NORM Rating
4-hour Emergency Rating =400 MVA
2-hour Emergency Rating =500 MVA
1-hour Emergency Rating =550 MVA
30-min Emergency Rating =600 MVA Peak modeled EMER #1 Rating
15-min Emergency Rating =650 MVA Peak modeled EMER #2 Rating
5-min Emergency Rating =700 MVA
7.Emergency Facility Ratings with a time value less than 15 minutes can only be used
for extenuating circumstances and only when its use is verified and acceptable by
both the TOP and the RC.
8.Peak's analysis tools are also able to utilize dynamic Facility Ratings in Real-time
operations.If a TOP uses dynamic Facility Ratings in Real-time operations analysis
tools,the TOP shall coordinate with Peak modeling engineers to facilitate Peak's
implementation of those dynamic Facility Ratings in Peak's models for use in Real-
time operations.The objective is for the TOP and the RC to be using the same
Facility Ratings at any given point in time.
Reference Table 1 -Facility Ratings Table and Examples for sample Facility Ratings that may
be used in the Operations Horizon.
Facility Normal Rating Emergency Rating #1 EmergencyRating #2
Facility TOP-provides TOP-provides short-term TOP-provides short-term
Name Normal Rating Emergency Rating #1 Emergency Rating #2
(continuous
operation Peak uses this for the Peak uses this for the EMER
rating)EMER #1 limit #2 limit
Peak uses this If the TOP uses more than If the TOP uses more than
for the NORM three Facility Ratings in its three Facility Ratings in its
limit analysis tools,Peak will use analysis tools,Peak will use
the TOP-provided the TOP-provided Emergency
Emergency Rating that has Rating that has the shortest
the second shortest time time value,no less than a 15-
value.minute Emergency Rating.
Example 1 300 MVA 450 MVA (4-hour)550 MVA (1-hour)
Example 2 200 MVA 300 MVA (4-hour)300 MVA (4-hour)
Example 3 600 MVA 800 MVA (1-hour)900 MVA (15-min)
Example 4 100 MVA 175 MVA (2-hour)225 MVA (30-min)
Example 5 500 MVA 500 MVA (time N/A)500 MVA (time N/A)
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Example 6 Ambient Ambient temperature Ambient temperature
temperature calculated calculated
calculated
Table 1 -Facility Ratings Table and Examples
Communication of Facility Ratings
9.The TOP shall communicate to the RC the following Facility Ratings:
a.The Facility Ratings it uses in operations as implemented in its analysis tools.
b.If a TOP uses different sets of Facility Ratings for different seasons,the TOP
shall communicate those seasonal Facility Ratings to the RC.
10.TOPs are responsible for communicating to the RC any changes to the Facility
Ratings used in operations.This includes any temporary Facility Ratings that may be
implemented and changes to seasonal Facility Ratings (e.g.,when the TOP stops
using summer seasonal ratings and begins using fall seasonal ratings.)Once
communicated,Peak will implement the changes in its models.
11.TOPs shall communicate Facility Ratings according to the method described in the
RC instructions.
System Voltage Limits
System Operating Limits used in the Operations Horizon include Facility Ratings,System
Voltage Limits and stability limitations.This section focuses on System Voltage Limits and
describes how System Voltage Limits are to be established and communicated to the RC.
System Voltage Limits are defined as follows for the purposes of the SOL Methodology:
The maximum and minimum steady-state voltage limits (both normal and emergency)
that provide for acceptable System performance.
System Voltage Limits are SOLs.System Voltage Limits apply to the BES and are typically
monitored at physical substation buses,though other points in the system may be monitored
as necessary.
It is important that the TOPs and the RC use the same set of System Voltage Limits for
assessments within the Operations Horizon,including seasonal planning studies,outage
coordination studies,special studies,OPAs and RTAs.While it is acceptable to use general or
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more stringent voltage limits to flag potential reliability issues,the established System Voltage
Limits must be ultimately used for assessments within the Operations Horizon1°.
Operating within Low System Voltage Limits ensures that the buses across the BES have
adequate voltage to support reliable operations of the BES.
Operating within High System Voltage Limits ensures that the system does not operate at
unacceptably high voltage levels,and that the equipment connected to the bus is not
subjected to voltages that exceed the equipment voltage rating.When equipment is subjected
to voltages that are higher than the equipment's voltage rating,the equipment may be
damaged and may not function properly when called upon.
It is important to distinguish System Voltage Limits from voltage stability limits.System
Voltage Limits address the steady state voltage of the system,while voltage stability limits
exist specifically to address voltage instability risks based on post-transient analysis.Voltage
stability limits are addressed in a subsequent section of the SOL Methodology.
TOPs shall establish System Voltage Limits according to the following:
1.TOPs are responsible for the establishment of System Voltage Limits for the
substation buses that exist within their TOP Area.TOPs have flexibility to modify
these limits as necessary based on actual or expected conditions within the bounds
of the subsequent requirements listed below,provided the changes are justified for
reliability and a technically sound rationale can be provided.
2.System Voltage Limits are applied to BES substation buses excluding the following:
a.Line side series capacitor buses
b.Line side series reactor buses
c.Dedicated shunt capacitor buses
d.Dedicated shunt reactor buses
e.Metering buses,fictitious buses or other buses that model points of
interconnection solely for measuring electrical quantities,and,
f.Other buses specifically excluded by the TOP in whose TOP Area the buses
reside,provided the exclusion is justified for reliability and is documented
10 Some entities might use generic (or more stringent)voltage limits that may exist in planning models that
do not reflect the System Voltage Limits that are used in actual operations.
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3.While it is expected that TOPs take steps to coordinate the development of System
Voltage Limits as described in the Coordination Responsibilities section of the SOL
Methodology,it is the specific responsibility of TOPs to agree on the System Voltage
Limits for buses that connect to adjacent TOPs.If the TOPs cannot agree,the most
limiting System Voltage Limits will apply as a default.If this default poses an
unfounded restriction or a reliability issue for the interconnecting TOPs,the TOPs
must collaborate with Peak to reach a resolution.
4.System Voltage Limits must provide for reliable operations.If a TOP provides
System Voltage Limits that Peak determines to be detrimental to the reliable
operation of the BES,Peak may request a technical justification for the use of such
limits and may prescribe System Voltage Limits.
5.System Voltage Limits must respect voltage limits identified in Nuclear Plant
Interface Requirements.
6.Low System Voltage Limits must not be lower than a value that triggers operation of
UVLS.
7.Normal High System Voltage Limits must respect the voltage ratings of the
connected equipment.
8.Emergency High System Voltage Limits must respect Protection Systems that trip
BES Facilities in response to high voltages.
9.For any applicable substation bus,System Voltage Limits must include the following:
a.A Normal Low System Voltage Limit -the low voltage limit that is used and
monitored for actuallpre-Contingency operations.An actuallpre-Contingency
voltage below a Normal Low System Voltage Limit is an SOL exceedance
and indicates that TOPs need to take action,if mitigation options exist,to
increase the actuallpre-Contingency voltage above the limit.
b.An EmergencyLow System Voltage Limit -the low voltage limit that is
used for emergency operations and is otherwise monitored for the post-
Contingency state.A calculated post-Contingency voltage below an
Emergency Low System Voltage Limit is an SOL Exceedance and requires
pre-Contingency action,if mitigation options exist,to increase the calculated
post-Contingency voltage above the limit.
c.A Normal High System Voltage Limit -the high voltage limit that,if
exceeded in actuallpre-Contingency operations,represents an unacceptably
high voltage (as determined by the TOP)at the bus.Normal High System
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Voltage Limits are used and monitored for actuallpre-Contingency operations.
When actuallpre-Contingency voltage is above a Normal High System
Voltage Limit,an SOL is being exceeded,and TOPs need to take action,if
mitigation options exist,to decrease the actuallpre-Contingency voltage
below the limit.
d.An EmergencyHigh System Voltage Limit_-the high voltage limit that is
used for emergency operations and is otherwise monitored for the post-
Contingency state.Emergency High System Voltage Limits should be
established such that they are actionable by the TOP for the calculated post-
Contingency state,i.e.,when Real-time Assessments indicate that an
Emergency High System Voltage Limit is exceeded in the calculated post-
Contingency state,the indication results in pre-Contingent System Operator
action to reduce calculated post-Contingency voltage to within the limit.A
calculated post-Contingency voltage above an Emergency High System
Voltage Limit is an SOL Exceedance and requires pre-Contingency action,if
mitigation options exist,to decrease the calculated post-Contingency voltage
below the limit.
Table 2 -System Voltage Limits below summarizes System Voltage Limit monitoring:
Normal High/Low EmergencyHigh/Low
Real-time:Real-time:
A.Monitored in Monitored in SCADA or State Estimation for actual exceedance
SCADA or State
Estimation for Monitored in RTCA (or equivalent)for calculated post-
actual Contingencyexceedance
exceedance Study:
Study:Monitored for pre-Contingency exceedance
B.Monitored for Monitored in Contingency Analysis for calculated post-pre-Contingency exceedanceContingency
exceedance
Table 2 -System Voltage Limits
Communication of System Voltage Limits
10.TOPs shall communicate System Voltage Limits according to the method described
in the RC instructions.The TOP shall communicate any changes in System Voltage
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Limits (made in response to actual or expected system conditions)to the RC and to
impacted TOPs.
Stability Limitations
Transient stability limits and voltage stability limitations are SOLs.Transient and voltage
instability in Real-time operations is generally assessed in one of two ways,either of which is
acceptable:
Through the use of advanced Real-time applications that assess the system's
response to simulated Contingency events,which may include system transfer
scenarios.
Through the use of predetermined limits established in offline studies which,if
operated within,are expected to result in acceptable stability performance in
response to the simulated Contingency event.
If method described in the second bullet is used,it is the responsibility of the TOP to
determine when it is appropriate to use stability limitations established in previous studies,or
whether expected system conditions warrant performing new studies to revise those stability
limitations used in Real-time operations.
Both methods must meet the performance criteria specified in the SOL Methodology.
When interface/cutplane stability limitations are established,they should be established in a
manner that most accurately and directly addresses the instability risk,for example a stability
limitation should be established on an interface/cutplane that most accurately and directly
monitors the instability risk that may not coincide with defined WECC Paths.Neither historical
presumptions/practices regarding system monitoring nor commerciallcontractual
arrangements should influence where stability limitations are most accurately established and
monitored for reliability.
Transient Analysis Methodology
1.It is up to the TOP and/or the RC to determine if and what types of operational
transient studies are required for a given season,planned outage or operational
scenario.For example,if a TOP or the RC determines,based on experience,
engineering judgment and knowledge of the system,that a planned transmission or
generation outage might pose a risk of transient instability for the next worst single
P1 Contingency or credible MC,the TOP should perform the appropriate transient
analyses to identify those risks.
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2.If an allowable UVLS,UFLS or a RAS is relied upon to address a transient instability
phenomenon,the transient analysis must include the actions of these schemes to
ensure that the schemes adequately address the reliability issues.Associated study
reports or Operating Plans must include a description of the actions and timing of
these schemes.
3.Transient studies must model applicable Facility outages that are planned for the
period of the study and must use appropriate load levels.
4.Available peak and off-peak (light load)loading conditions should be screened for
the period under study to determine the conditions under which instabilities occur.
The TOP and/or the RC may run studies on only those specific set of conditions for
subsequent studies.The intent is to do due diligence to identify instability risks for
both expected heavy-load conditions and expected light-load conditions.
5.Single P1 Contingencies shall include the more severe or impactful of single line-to-
ground Faults or three-phase Faults as determined by the TOP or RC.
6.Three-phase and single line-to-ground Faults will be simulated at no more than 10
percent from each point of connection with bus,or the more severe of the high or low
side of an autotransformer.
7.The Fault duration applied should be based on the total known Fault clearing times
or as specified in the corresponding planning studies for the applicable voltage level.
For credible MC events,the appropriate clearing times must be modeled.
8.Transient analysis must extend for at least 10 seconds following the initiating event,
or longer if swings are not damped.
9.The dynamics parameter file used for transient studies shall be based upon the
approved WECC dynamics file with the following additions:a generic mho distance
relay model that is set for all Facilities 100kV and above with zone 1 setting of 80
percent,a zone 2 setting of 120 percent with a 24 cycle delay and a zone 3 setting of
140 percent with a 36 cycle delay shall be included in the dynamics model file.These
relays shall be set to "non-tripping"mode.Any actions by relay models during a
simulation must be investigated and,if warranted,specific relay models and settings
applied.Entities may modify the generic step distance relay settings specified above
to reflect their protection philosophy.
10.A generic voltage and frequency ride-through relay model should be installed on all
generators at the point of interconnection that models the voltage and frequency
ride-through capabilities specified in PRC-024-2.This generic relay may be set to
"non-tripping"but any actions by the relay must be checked against the unit actual
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tripping settings and the appropriate actions taken.For generators for which the GO
has provided exceptions to the requirements of PRC-024-3 under requirement R3,
the specific tripping points must be modeled and any appropriate actions taken.
11.The buses monitored for transient system performance should be determined based
on engineering judgment.
Transient Analysis Performance Requirements
Transient system performance requirements are indicated in Table 3 -Transient System
Performance Requirements below.
.Required forRequiredfor
Transient System Performance Single P1 CredibleMultipleContingenciesContingencies
The system must demonstrate positive damping.The Yes Yes
system is considered to demonstrate acceptable positive
damping if the damping ratio of the power system
oscillations is 3%or greater.The signals used generally
include power angle,voltage and/or frequency.An
example of damping ratio calculation is provided in
Appendix B.
There may be instances where it is prudent to allow for a
damping ratio less than 3%.In such cases,studies must
demonstrate that the damping provides for an acceptable
level of reliability,and the use of the lower damping
threshold must be reviewed and accepted by impacted
TOPs and by the RC.
The BES must remain transiently stable,and must not Yes Yes
Cascade or experience uncontrolled separation as
described in the SOL Methodology.System frequency in
the interconnected system as a whole must not trigger
UFLS.Any controlled islands formed must remain stable.
Transient voltage or frequency dips and settling points Yes No
shall not violate in magnitude and duration:
1.Generator ride-through capabilities as specified by
PRC-024-2;no BES generating unit shall pull out
of synchronism (or trip)in response to transient
system performance;UFLS shall not be triggered.
2.Nuclear plant interface requirements.
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3.Known BES equipment trip or failure levels,e.g.
surge arrestors,transformer saturation levels,
generator over-excitation.
General Notes:
1.UVLS or other automatic mitigation actions are permitted as specified within Peak
Reliability's SOL/IROL methodology.
2.A generator being disconnected from the system by Fault clearing action or by a RAS
is not considered losing synchronism.Additionally,small (<25 MW)non-BES
generators that may trip are not considered as losing synchronism.
3.If known BES equipment trip settings are exceeded,the appropriate actions must be
modeled in the simulations.
4.For generators that the GO or NPIR has identified as not being able to meet the PRC-
024-2 requirements,either the unit must be tripped,or the Point of Interconnection
(POI)frequency verified against the unit established trip values and the appropriate
action taken.
Table 3 -Transient System Performance Requirements
Establishment of Transient StabilityLimits
12.Transient stability limits are established to meet the transient system performance
requirements in Table 3 -Transient System Performance Requirements.
13.Transient stability limits do not include operating margins.Operating margins are
specified in the corresponding Operating Plans.
14.If TOP or RC transient analyses are technically accurate yet the results of the studies
do not agree (i.e.,if one TOP's analysis results differ from another TOP's analysis
results,or if a TOP's analysis results differ from the RC's analysis results),then the
most limiting analysis results are used as a default if the differences cannot be
worked out.
Communication of Transient StabilityLimits
15.When TOP studies indicate the presence of transient instability risks (whether
contained or uncontained),the TOP shall communicate the study results to Peak and
to impacted TOPs for further review.This communication should occur in a timely
manner to allow for proper coordination and preparation prior to Real-time
operations.
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16.TOPs shall communicate transient stability limits according to the method described
in the RC instructions.
Post-Transient Analysis Methodology
The post-transient period is the timeframe after any initial swings and transient effects of a
disturbance are over,but prior to AGC or operator actions.Post-transient analysis is
performed through a governor power flow study.
17.The starting point of the analysis is the system condition with the event modeled and
taking into account the effects of allowable automatic actions as described in the
Allowed Uses of Automatic Mitigation Schernes in the Operations Horizon section of
the SOL Methodology,e.g.,UVLS,UFLS and RAS actions.
18.Impacts of the composite load model as observed in transient analyses shall not be
included in the post-transient analysis since the restoration of this load is not under
the control of operating personnel.For example,a transient study indicates that a
Contingency results in load being lost due to composite load model behavior in the
transient timeframe.When performing a subsequent post-transient analysis of that
Contingency,the load shall not be reduced by the amount of expected loss that
occurred in the transient analysis in response to the composite load model.
19.The Contingencies being studied shall be run with the area interchange controls and
phase shifters controls disabled.Tap-Changer Under Load (TCUL),shunt capacitors
and Static Var Compensators (SVC)that are automatically controlled may be
allowed to switch provided the automatic control settings are accurately modeled and
the devices will switch within 20 seconds or less11.Generators and SVCs shall be set
to regulate the terminal bus voltage unless reactive droop compensation is explicitly
modeled or SVC control signals are received from a remote bus.
20.RAS actions shall be accounted for by taking the same specific actions as the RAS,
i.e.,the same generators will be tripped and the same loads disconnected.Loss of
generation shall be accounted for in the power flow by scaling up the generation in
the interconnected system,with Pmax limits imposed,excluding negative generators
and negative loads.Any increase or decrease in generation shall be done on the
weighted MW margin (up/down range)or the closest equivalent based on the
11 The 20 second reaction time for switchable reactive devices is to ensure coordination with generator
Maximum Excitation Limiter (OEL)settings.Typical OEL's will begin to reduce a generator's reactive
output to safe operating levels within a 20-second window.Reference IEEE Recommended Practice for
Excitation System Models for Power System Stability Studies,IEEE Std.421.5-2005 (Revision of IEEE
Std.421.5-1992),2006,pp.0_1-85.
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program used.Alternatively,units may respond in proportion to the nameplate
ratings.Base-loaded units must be blocked from responding.
Establishment of Voltaqe StabilityLimits
21.Voltage stability limits are SOLs.Voltage stability limits are established using
transient (for fast voltage collapse risks)and post-transient analysis techniques.One
representation of a voltage stability limit is the maximum pre-Contingency megawatt
power transfer for which a post-Contingency solution can be achieved for the limiting
(critical)Contingency (i.e.,the last good solution established the voltage stability
limit).P-V and V-Q analysis techniques are used as necessary for the determination
of voltage stability limits.While megawatt power transfer represents one approach
for defining a voltage stability limit,other units of measure (such as VAR limits)may
be used,provided this approach is coordinated between the TOP and the RC.
Reference Figure 3 -Sample P-V Curve as an example of a MW power transfer
approach to defining a voltage stability limit.
22.The voltage stability limit does not include operating margins.Operating margins are
specified in the corresponding Operating Plans.
23.If TOP or RC post-transient analyses are technically accurate yet the results of the
studies do not agree (i.e.,if one TOP's analysis results differ from another TOP's
analysis results,or if a TOP's analysis results differ from the RC's analysis results),
then the most limiting analysis results are used as a default if the differences cannot
be worked out.
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Reference Figure 3 -Sample P-V Curve below for an example of a PV curve for determining
voltage stability limits.
>N-0
I The 'knee'of the curve defines
the voltage stability limit,i.e.,
the last valid solution point.
I
I
I
I
I
I
P Power Transfer,P (MW)
Figure 3 -Sample P-V Curve
Communication of Voltage StabilityLimits
24.When TOP studies indicate the presence of voltage instability risks (whether
contained or uncontained),the TOP shall communicate the study results to Peak and
to impacted TOPs for further review.This communication should occur in a timely
manner to allow for proper coordination and preparation prior to Real-time
operations.
25.Voltage stability limits shall be communicated per the posted RC instructions.
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R.System Stressing Methodology
The objective of this system stressing methodology is to either identify instability risks or to
rule them out for all practical purposes for Operating Horizon studies.
If instability risks are identified,there is a need to establish stability limitations (which
may include implementing Real-time stability limit calculators)and/or to establish
Operating Plans to address those instability risks.
If instability risks are ruled out for expected operating conditions,then subsequent
reliability analyses might exclude stability analyses for the Operating Horizon,
provided system conditions are comparable to those represented in prior studies.
If instability risks can be ruled out for expected operating conditions,then subsequent
reliability analyses -i.e.,Operational Planning Analyses (OPA)and Real-time Assessments
(RTA)-using steady state Contingency analysis of actual or expected conditions,are
sufficient to confirm that the system can be reliably operated within acceptable pre-and post-
Contingency performance requirements with regard to Facility Ratings and System Voltage
Limits.
Differinq Objectivesfor System Stressinq
Transfer analyses that stress the power system are performed to determine the pre-and post-
Contingency reliability issues that can be encountered as transfers increase into a load area
or across a transmission interface.How far the system is stressed as part of transfer analyses
depends on the purposes and objectives of the analysis.
If the purpose of the transfer analyses is to determine Transfer Capability (TC)or TTC,the
system generally needs to be stressed only to the point where a reliability limitation is
encountered (with an applicable margin).In principle,TCs are generally determined by
stressing the system until either of the following reliability constraints is encountered:
In the pre-Contingency state,flows exceed normal Facility Ratings,voltages fall
outside normal System Voltage Limits or instability occurs (i.e.,the system is
stressed to the point of unacceptable pre-Contingency performance with regard to
thermal,steady-state voltage or instability constraints).
In the post-Contingency state,flows exceed emergency Facility Ratings,voltages fall
outside emergency System Voltage Limits or instability occurs (i.e.,the system is
stressed to the point of unacceptable post-Contingency performance with regard to
thermal,steady-state voltage or instability constraints).
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Most Paths in WECC are either thermally limited or steady-state voltage limited,as opposed
to transient stability or voltage stability limited.For these Paths,transfer analyses have shown
that the first reliability limitations encountered are post-Contingency exceedances of
emergency Facility Ratings or emergency System Voltage Limits.For example,when
stressing a Path,transfer analyses indicate that at a certain level of transfer,a single P1
Contingency results in exceedance of another Facility's emergency Facility Rating.Similarly,
these transfer analyses may indicate that at a certain level of transfer,a P1 Contingency
results in voltage at a bus falling outside its emergency System Voltage Limit.
While TC studies do not require that the system be stressed appreciably beyond the point of
encountering the first reliability limitation,the same cannot be said for transfer analyses that
are performed for purposes of determining whether instability risks exist for expected system
conditions.Because actions may be taken in the actual system conditions that mitigate
thermal and voltage limitations identified as a first reliability limitation,it may be necessary to
identify where subsequent operation may approach a point of instability.
To adequately determine whether instability risks exist for expected system conditions for a
given transmission interface or load area,the system must be stressed beyond the point
where thermal or voltage limitations are encountered.The question is:how far does the
system need to be stressed before instability risks can be ruled out for all practical purposes?
Note that transfer analyses for purposes of determining TC or TTC are outside the scope of
the SOL Methodology.
Stressinq Requirementsto Determine InstabilityRisks
Transient instability,voltage instability or Cascading may occur in response to a single P1
Contingency or a credible MC under stressed conditions.Engineers perform studies that
evaluate the system under stressed conditions to identify these risks.As was stated in the
introduction of this section,the objective of this system stressing methodology is to either
identify instability risks or to rule them out.Under this methodology,it is the primary
responsibility of the TOP to identify or rule out instability risks and to determine how far
transmission interfaces and load areas should be stressed to accomplish this intended
objective.System stressing requirements depend on several factors and therefore cannot be
specified in a one-size-fits-all approach.While the system should be stressed far enough to
accomplish the intended objective,the expectation of this methodology is to stress the system
up to -and slightly beyond -reasonable maximum stressed conditions.It is not the intent of
this methodology for TOPs to stress the system unrealistically or to stress the system to levels
appreciably beyond those that are practically or realistically achievable.
This methodology should be applied to applicable studies performed in the Operations
Horizon including,at a minimum,seasonal planning studies and outage coordination studies
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as determined to be necessary by the TOP.While the stressing methodology may optionally
be applied to Operational Planning Analyses and Real-time Assessments,it is not required.
For transmission interfaces that span multiple TOP Areas,the TOPs that operate the Facilities
on the interface are expected to coordinate to determine appropriate levels of stressing
necessary to identify or rule out instability risks.TOPs are expected to document stressing
levels performed in operations planning studies and to communicate these levels and the
results of these analyses to the RC when instability or Cascading is identified.
The following considerations should be used as a guideline to determine appropriate levels of
system stressing:
1.Source area is exhausted -When stressing a transmission interface,in some cases
it is possible to maximize the source area in the simulation before any reliability
issues (thermal,voltage or instability)are encountered.If the source area is
exhausted in simulations,then it can be concluded that there is no way to realistically
simulate any additional transfers.Load should not be scaled unrealistically as part of
increasing exports.For example,when simulating exports,it may be unreasonable to
scale load down by 50 percent of its expected value to simulate exports.The TOP is
expected to determine reasonable uses of load as a mechanism for simulating
exports.
2.If the source is maximized before either the nose of a PV or VQ curve is reached,
before transient instability occurs,or before Cascading takes place (per the
Cascading test outlined in the SOL Methodology),then it can be concluded that no
instability or Cascading risks practically exist for the interface and there is no
reliability need to establish stability limitations for the interface or load area.Different
methodologies will be used (as further discussed below)for transmission interfaces
where source generation cannot be maximized in the simulation.
3.Sink area is depleted -When stressing an interface into a load area,it is possible to
de-commit or reduce the output of all generators internal to the load area (i.e.,serve
the load with ~100 percent imports)before any pre-or post-Contingency reliability
issues (thermal,voltage or instability)are encountered.Entities should model the
expected minimum generation commitment in the load sink area at the expected
maximum import level and simulate largest generation Contingency as part of
simulations.If the generation internal to the sink load area is decreased to the
minimum generation commitment level and the sink's load is modeled at reasonably
expected maximum conditions,then it can be concluded that there is no practical
way to simulate any additional imports into the area.Load should not be scaled
unrealistically as part of increasing imports.For example,when simulating imports,it
may be unreasonable to scale load in the sink area up by 150 percent of its expected
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value to simulate imports.The TOP is expected to determine reasonable uses of
load as a mechanism for simulating imports.
4.If the generation internal to the sink load area is depleted and load is maximized
either before the nose of a PV or VQ curve is reached,before transient instability
occurs,or before Cascading takes place (per the Cascading test outlined in the SOL
Methodology),then it can be concluded that no stability limits or Cascading risks
practically exist for the load area and there is no reliability need to establish a
stability limit for the load area.
5.It may be possible to simulate flow on an interface or into a load area to levels that
are unrealistic for operations.While it is expected that the system be stressed
beyond the historical 2.5-to-5 percent levels for identifying or ruling out instability
risks,the TOP,in collaboration with neighboring TOPs as necessary,are expected to
determine reasonable maximum stressing conditions to identify or rule out instability
risks.If the system is stressed to levels just beyond those determined by impacted
TOPs as being reasonably expected maximums and no instability occurs in the
simulations,or simulated flows do not reach the level where potential Cascading can
occur,then it can be concluded that no instability or Cascading risks practically exist
for the interface or load area and thus there is no reliability need for establishing
stability limits or stability-related Operating Plans.
6.It is possible to stress the system to a point where potential Cascading is
encountered.Cascading tests should be performed consistent with the Instability,
Cascading,Uncontrolled Separation and IROLs section of the SOL Methodology.
This analysis assumes that pre-and post-Contingency flows are below applicable
Facility Ratings prior to the transfer analysis.
7.System stressing studies may result in transient instability or the nose of a PV or VQ
curve being reached12 either under pre-Contingency conditions or upon occurrence
of a single P1 Contingency or credible MC.This condition indicates the presence of
an instability risk and thus the need to establish a transient or voltage stability limit or
to otherwise manage the instability risk via an Operating Plan.
8.Any instability or Cascading risks identified as a result of applying this system
stressing methodology must be communicated to the RC.For identified Cascading or
12 If the nose is not reached and different solving techniques do not result in a solution,then the last
solved solution determines the stability limit.
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instability risks,the RC will collaborate with the TOP(s)in the establishment of
stability limitations and Operating Plans to mitigate these risks.
S.Instability,Cascading,Uncontrolled Separation and IROLs
IROLs are distinguished from SOLs in a few ways:
1.An IROL is a subset of SOLs that is associated with instability,uncontrolled
separation or Cascading.SOLs include a broader set of limitations including Facility
Ratings and System Voltage Limits,and certain non-IROL stability limitations.
2.IROL exceedance is associated with a heightened risk to the reliability of the BES.
The reliability consequences associated with exceeding an IROL are more severe
and adversely impactful than the reliability consequences associated with exceeding
an SOL that is not an IROL.This distinction is seen in the following:
a.Per the NERC Reliability Standards,an IROL carries with it a required
mitigation time,the IROL Tv,which can be no longer than 30 minutes.When
an IROL is exceeded,the NERC Reliability Standards require that the IROL
be mitigated within the IROL Tv.
b.While the NERC Reliability Standards require that any SOL exceedance
identified in Operational Planning Analyses must have an associated
Operating Plan,the standards require that IROLs have an Operating
Plan/Process/Procedure that contains steps up to and including load
shedding to prevent exceeding the IROL.
3.IROLs should be established such that when an IROL is exceeded,the
Interconnection has entered into an N-1 or credible N-2 insecure state,i.e.,the most
limiting single P1 Contingency or credible MC could result in instability,uncontrolled
separation or Cascading outages that adversely impact the reliability of the BES.
An IROL is defined in the NERC Glossary of Terms as:
A System Operating Limit that,if violated,could lead to instability,uncontrolled
separation,or Cascading outages"that adversely impact the reliability of the Bulk
Electric System.
13 On September 13,2012,FERC issued an Order approving NERC's request to modify the reference to
"Cascading Outages"to "Cascading outages"within the definition of IROL due to the fact that the
definition of "Cascading Outages"was previously remanded by FERC.
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By definition,IROLs are SOLs that could lead to any of the following three operational
phenomena:
Instability,
Uncontrolled separation,or
Cascading outages
It is observed that each of these three phenomena can be interpreted to have very different
meanings and applications,which can lead to inconsistencies in IROL establishment.The
following sections provide a brief characterization of each of the three phenomena with the
objective of providing for more consistency in the establishment of IROLs in the Operations
Horizon.
Instability
A major challenge the industry faces is with the word "instability"in the IROL definition.Per
the existing definition,an IROL is an SOL which,if exceeded,could result in instability.
However there are many forms of instability,each with a wide spectrum of reliability impacts -
from little to no impact,such as losing a unit due to "instability,"all the way to major and
devastating impact,such as losing a major portion of the BES due to instability.
It is recognized that not all types of instability pose the same degree of risk to the reliability of
the BES.At the same time,it also is recognized that regardless of the type of instability,it is
critical that studieslassessment determine how -or if -the instability will be contained,and to
understand the impact that the instability may have on the BES.
Accordingly,transient or voltage instability that cannot be demonstrated through studies to be
confined to a localized,contained area of the BES effectively has a critical impact on the
operation of the Interconnection,and therefore warrants establishment of an IROL.
Uncontrolled Separation
Uncontrolled separation (which includes uncontrolled islanding)occurs when studies indicate
that a Contingency is expected to result in rotor angle instability or to trigger relay action which
causes the system to break apart into major islands in an unintended (non-deliberate)
manner.The determination of uncontrolled separation takes into consideration transient
instability phenomena and relay actions that cause islands to form.
It is recognized that transient instability may result in the loss of small pockets of generation
and load,or radially connected subsystems that do not warrant establishment of an IROL and
do not constitute a violation of the credible MC performance requirements stated in section
entitled Performance Requirernents for Always Credible and Applicable Conditionally Credible
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MCs.In such scenarios,the loss of a unit (or group of units)may have little to no impact on
the reliable operation of the interconnected system.
Uncontrolled separation can be understood by comparing it to the following description of
controlled separation:
4.Controlled separation is achieved when there is an automatic scheme that exists and
is specifically designed for the purposes of:
a.Intentionallyseparating the system.
i.Note that such schemes may be accompanied by generation drop
schemes or UFLS that are designed to shed load or drop generation
to achieve generationlload equilibrium upon occurrence of the
controlled separation.
b.Intentionallymitigating known separation conditions.
i.I.e.,a scheme that is designed specifically to drop load or generation
to achieve generationlload equilibrium upon a known Contingency
event that poses a separation risk.
5.Post-Contingency islanding due to transmission configuration does not constitute
uncontrolled separation.
a.There are occasions where planned or forced transmission outages can
render the transmission system as being configured in a manner where the
next Contingency (single P1 Contingency or credible MC)can result in the
creation of an island.Operators are made aware of these scenarios through
outage studies,OPAs and/or RTAs,and are expected to have Operating
Plans that would address the condition in a reliable manner.Such conditions
should consider the associated risks and mitigation mechanisms available;
however,they are excluded from the scope of uncontrolled separation for the
purposes of IROL establishment.
6.Examples of controlled separation:
a.Example 1:A RAS is designed specifically to break the system into islands in
an intentional and controlled manner in response to a specific Contingency
event(s).Supporting generation drop and/or UFLS are in place to achieve
load/generation equilibrium.
b.Example 2:A UFLS is specifically designed to address a known condition
where a credible MC is expected to create an island condition.
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Cascadinq
Cascading is defined in the NERC Glossary of Terms as:
The uncontrolled successive loss of System Elements triggered by an incident at any
location.Cascading results in widespread electric service interruption that cannot be
restrained from sequentially spreading beyond an area predetermined by studies.
Cascading can occur when studies indicate that a Contingency results in severe loading on a
Facility,triggering a chain reaction of Facility disconnections by relay action,equipment failure
or forced immediate manual disconnection of the Facility (for example,due to line sag or
public safety concerns).Per the definition,when Cascading occurs,the electric service
interruption cannot be restrained from sequentially spreading beyond an area pre-determined
by studies.
Instability can cause Cascading.When Cascading is a response to instability,the Cascading
will be addressed via a stability-related IROL.
Cascading test -If powerflow studies indicate that the successive tripping of Facilities stops
before the case diverges,then by definition,the phenomenon is not considered to be
Cascading,because the studies have effectively defined an "area predetermined by studies."
However,if the system collapses during the Cascading test,the area cannot be
"predetermined by studies,"and therefore it is concluded that the extent of successive tripping
of elements cannot be determined.When this is the case,an IROL is warranted.
Powerflow Cascadinq Test:
7.Run Contingency analysis and flag single P1 Contingencies and credible MCs that
result in post-Contingency loading in excess of the lower of:
a.The Facility(ies)'s trip setting
b.125 percent of the highest Emergency Rating
8.For each flagged Contingency,open both the contingent element(s)that cause(s)the
post-Contingency loading and all consequent Facilities that overload in excess of (7)
(a)or (b)above.Run powerflow.
9.Repeat step (8)for any newly overloaded Facility(ies)in excess of (7)(a)or (b)
above.Continue with this process until no more Facilities are removed from service
or until the powerflow solution diverges.
10.If the subsequent tripping of Facilities stops prior to case divergence,then it can be
concluded that the area of impact is predetermined by studies,and thus Cascading
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does not occur.If the case diverges during the Cascading test,then it can be
concluded that Cascading occurs.
T.IROL Establishment
The SOL Methodology considers IROLs to be limits that are identified one or more days prior
to Real-time14.IROLs will generally be identified and established as part of seasonal planning
analyses,through special studies and through the IRO-017-1 Outage Coordination Process.
While it is possible to identify an IROL in the Operational Planning Analysis timeframe,this
should be a rare occurrence since the IRO-017-1 Outage Coordination Process should
identify reliability issues prior to the OPA timeframe,providing for cancellation of outages that
pose the significant reliability risk.
An IROL is a limit,not a condition.The IROL term is often erroneously used to represent a
condition.It is sometimes said that "instability is an IROL"or "Cascading is an IROL."
Instability,Cascading or uncontrolled separation are phenomena,they are not an IROL.An
IROL is a limit put in place to prevent instability,Cascading or uncontrolled separation from
occurring.
When the SOL Methodology uses the term IROL,it is used in the context of the IROL being
identified in studies performed one or more days prior to Real-time.Per the SOL Methodology,
IROLs are always pre-identified through studies.However,it is acknowledged that
unanticipated Real-time events can render the BES in a state where Real-time Assessments
indicate that the system is not secure for the next single P1 Contingency or credible MC.Such
N-1 or N-2 insecure conditions are addressed through Operating Plans outside of the
auspices of an IROL;however,these conditions are treated with the same level of urgency as
IROLs.This approach is consistent with the notion that an IROL is a limit and not a condition.
When such unanticipated conditions unexpectedly occur in Real-time operations,Peak
Reliability Coordinator System Operators are expected to bring the system to an N-1 or
credible N-2 secure state within 30 minutes,in accordance with internal Operating Plans.
The RC is responsible for declaring IROLs.TOPs are not responsible for declaring IROLs;
however,TOPs are responsible for communicating and collaborating with the RC when
studies (seasonal studies,special studies,outage studies or OPAs)result in instability
(whether contained or uncontained),Cascading or uncontrolled separation as described in the
14 While the value of the identified IROL can be calculated in Real-time,the identification of the IROL
occurs one or more days prior to Real-time.
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SOL Methodology.Upon this communication,the RC then collaborates with the TOP to
determine if an IROL needs to be established to address these risks.
Lonq-Term IROLs versus Planned Outage Condition IROLs
The SOL Methodology distinguishes long-term IROLs from Planned Outage Condition IROLs.
Lonq-Term IROLs
While long-term IROLs may only pose a risk under certain loading conditions or generation
dispatch conditions,they are not a function of planned outages.Long-term IROLs may be in
effect at all times,or they may be in effect during certain specified system conditions unique to
that IROL;however,they generally remain as identified IROLs until physical system
reinforcements are made to address the associated risk of instability,uncontrolled separation
or Cascading.Long-term IROLs are established to prevent instability,uncontrolled separation
or Cascading as described in the SOL Methodology for:
1.Single P1 Contingencies
2.Credible MCs
3.N-1-1 and N-1-2 operations starting with an "all transmission Facilities in service"
case,without system adjustments
Long-term IROLs are identified through seasonal planning studies and through special studies
conducted by the RC,by the TOP(s)or by the RC in collaboration with the TOP(s).However,
it is the RC that ultimately declares IROLs for use in the Operations Horizon.Relevant
information for IROL identification can be gleaned from several sources including,for
example,prior operational experienceslevents and planning studies performed in association
with the NERC TPL standards,and from planning studies performed in association with FAC-
010-3 and corresponding requirements applicable to PCs and TPs in FAC-014-2.
Lonq-Term IROLs for N-1-1 and N-1-2 Operations (Referencinq Item 3 Above)
Application:
4.Addresses known N-1-1 and N-1-2 risks that could result in instability,Cascading or
uncontrolled separation as described in the SOL Methodology
5.Applicable to an "all transmission Facilities in service"starting point case(s)
6.Addresses N-1-1 and N-1-2 operations (without system adjustments)where:
a."N"is an "all transmission Facilities in service"case(s)
b.The first "-1"is a forced outage or a single P1 Contingency event
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c.The second "-1"is the next worst single P1 Contingency,or the "-2"is the
next worst Always Credible MC
7.Long-term IROLs are not established for N-2-1,or N-2-2 conditions,due to the low
probability of occurrence of the first "-2"Contingency event.
Purpose:
Long-term N-1-1 and N-1-2 IROLs are intended to pre-identify and prepare for the
following scenario:
8.The system is being operated in a "normal"mode.The system demonstrates
acceptable system performance for the pre-and Post-Contingency state.
9.A single P1 Contingency or a forcedlurgent outage of a single Facility occurs.
10.The system is now in a new and different state before system adjustments can be
made.
11.Based on this new state,the next single P1 Contingency or Always Credible MC
could result in instability,Cascading or uncontrolled separation as described in the
SOL Methodology,and thus the system is now in an N-1 (or credible N-2)insecure
state.
Rationale for Long-Term N-1-1 and N-1-2 IROLs:
N-1-1 and N-1-2 IROLs are identified and established to provide System Operators an
awareness of instances where a single P1 Contingency or a forcedlurgent outage on a
single Facility is pre-determined by studies to render the system in a state where the next
single P1 Contingency or Always Credible MC can result in instability,uncontrolled
separation or Cascading as described in the SOL Methodology.
12.Given an initial condition state of "all transmission Facilities in service"in a normal
mode of operation,if a single P1 Contingency or a forcedlurgent single Facility
outage causes engineersloperators to re-position the system with the specific
objective of preventing instability,Cascading or uncontrolled separation as described
in the SOL Methodology for the next worst single P1 Contingency or Always Credible
MC,then the system is in an N-1 or N-2 insecure state until those system
adjustments can be made to transition the system to an N-1 or N-2 secure state.
13.When N-1-1 or N-1-2 studies indicate that the first "-1"renders the system in an N-1
or N-2 insecure state where the next single P1 Contingency or Always Credible MC
can result in instability,Cascading or uncontrolled separation as described in the
SOL Methodology,a long-term IROL is warranted..This IROL would become
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effective when the first "-1"event occurs and would prevent the next Single P1
Contingency or Always Credible MC from resulting in instability,Cascading or
uncontrolled separation as described in the SOL Methodology.Such IROLs will be in
effect only upon a forcedlurgent outage or Contingency of the first "-1"Facility.
14.For such predetermined N-1-1 and N-1-2 IROLs,it is acceptable to operate the
system such that the first "-1"Contingency will result in exceeding the IROL,
provided that System Operators know that they are able to mitigate the IROL within
the IROL Tv after the "-1"Contingency event occurs.If System Operators are not
able to mitigate the IROL exceedance within the IROL Tv after the first "-1"
Contingency event occurs,then pre-Contingency actions must be taken such that
System Operators are able to mitigate the IROL exceedance within the IROL Tv after
the first "-1"Contingency occurs".
Process for Identifying Long-TermIROLs for N-1-1 and N-1-2 Conditions:
Long-term N-1-1 and N-1-2 IROLs are identified using transient analysis and/or post-
transient analysis techniques described in the SOL Methodology.The following analysis
process should be used to determine if an N-1-1 or an N-1-2 IROL should be established:
15.N-1-1 and N-1-2 analysis assumes an "all transmission Facilities in service"initial
condition.Assessments are based on reasonable max stressing conditions and
historical flows.Reference the system stressing methodology.
16.The first single P1 Contingency is simulated.
17.No system adjustments are made other than allowable automatic action such as
governor response,automatic capacitor switching,RAS,etc.
18.The next worst single P1 Contingency or Always Credible MC is then simulated to
determine if the Contingency results in instability,Cascading or uncontrolled
separation as described in the SOL Methodology.The analysis of this next worst
single P1 Contingency or Always Credible MC event should account for allowable
automatic schemes that are designed to address these Contingencies.
19.If the next single P1 Contingency or Always Credible MC results in instability,
Cascading or uncontrolled separation as described in the SOL Methodology,then
the condition indicates that system adjustments must be made after the first "-1"
*Reference FERC Order 705 paragraph 125,which states,"Therefore,the Commission proposed to
accept the definition of IROL Tv with the understanding that the only time it is acceptable to violate an
IROL is in the limited time after a contingency has occurred and the operators are taking action to
eliminate the violation."
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Contingency,but before the second Contingency,to prevent the instability,
Cascading or uncontrolled separation as described in the SOL Methodology from
occurring.This fact points to the presence of an IROL that would become effective
upon a forcedlurgent outage or Contingency of the first "-1"Facility.
20.Once these risks are identified,the N-1-1 and N-1-2 studies should then identify
system adjustments that must be made (and the timing associated with these
adjustments)after the first "-1"Contingency event to prevent the second
Contingency event from resulting in instability,Cascading or uncontrolled separation
as described in the SOL Methodology.These system adjustments should be taken
into consideration when developing the IROL Operating Plan.IROLs must be
determined that can be applied upon a forcedlurgent outage or a Contingency of the
first "-1"Facility.These IROLs can be pre-established values,or they can be
calculated in Real-time.
21.The lower of the relay setting or 125 percent Cascading test as described in the SOL
Methodology applies for the determination of Cascading.
22.For identified IROLs for N-1-1 and N-1-2 conditions,Real-time N-1-1 and N-1-2
analyses/calculations are prudent to provide System Operators awareness as to
whether that IROL would be expected to be exceeded upon a Contingency or a
forcedlurgent outage of the first "N-1"Facility.
Long-Term N-1-1 InstabilityIROL Example:
Studies show that the loss of Facility X is expected to render the system in a position
where a subsequent Contingency on Facility Y would result in wide-area voltage instability,
i.e.,that the loss of line X would render the system in an N-1 insecure state for
Contingency Y.An IROL is established to prevent the loss of Facility X,followed by a
Contingency of Facility Y,resulting in wide-area voltage instability.
23.The IROL exists on the monitored interface appropriate for determining wide-area
voltage instability for the loss of Facility Y.
24.For this example,the IROL is monitored as the maximum MW flow (the last good
solution)on the monitored interface above which the subsequent loss of Facility Y
results in wide-area voltage instability.
25.The IROL becomes effective when Facility X experiences a forcedlurgent outage.
The IROL is not in effect unless there is a forcedlurgent outage or Contingency of
Facility X.
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26.The IROL is exceeded when Facility X experiences a forcedlurgent outage and
subsequent Real-time Assessments indicate that the flow on the monitored interface
is above the value where the loss of Facility Y results in wide-area voltage instability.
The IROL can be a pre-established value,or it can be calculated in Real-time.
Planned Outage Condition (POC)IROLs
POC IROLs are established to prevent instability,Cascading or uncontrolled separation as
described in the SOL Methodology during planned outage conditions.POC IROLs are
temporary in nature and do not apply when the planned outage is not in effect.Additionally,
POC IROLs are established for the outage conditions as expected system conditions warrant.
For example,a planned outage for Facility XYZ during the month of August when loads are
high may require a POC IROL to be established for the duration of that outage;however,an
outage on that same Facility in November when loads are low may not require a POC IROL to
be established.
POC IROLs are established to prevent instability,uncontrolled separation or Cascading as
described in the SOL Methodology for:
Single P1 Contingencies
Credible MCs
POC IROLs are generally not established to address N-1-1 or N-1-2 operations during
planned outages;however,TOPs and the RC may determine that it is prudent to establish an
N-1-1 or an N-1-2 POC IROL for long-duration outages (such as those that are in effect for an
entire season)where the TOP and the RC collaboratively determine that there is a high risk
for N-1-1 or N-1-2 instability risks while the outage is in effect.
Identifyinq IROLs for Planned Outaqe Conditions
This section is intended to provide clarity on when IROLs should be established for planned
outage conditions,and to provide guidance on the method that should be employed to make
that determination.
When transmission or generation outages are planned,the system must be studied to
determine if the planned outage creates any new instability risks that otherwise would not
practically exist.When the system is operated in a "normal"mode,many types of limitations
exist -thermal,voltage or stability.In "normal"mode,the system is able to support transfers
throughout the various seasons that are fairly well understood.When planned outages are
brought into the equation,the system may not be able to support the transfer levels that it
otherwise would be able to support.TOPs routinely reduce TTCs in response to planned
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outage conditions as a preemptive measure to prevent commercial activity (schedules)from
resulting in SOL exceedances.
Per the IRO-017 Outage Coordination process,BAs,TOPs and the RC are expected to
perform studieslassessments to ensure that the BES will be in a reliable pre-and post-
Contingency state while an outage is in effect.Acceptable system performance as described
in the SOL Methodology is required while planned outages are implemented.
It is not the intent of the IRO-017 Outage Coordination Process or the SOL Methodology to be
highly prescriptive for study requirements related to planned outages.TOPs are responsible
for determining the level of study needed to achieve acceptable pre-and post-Contingency
system performance while the outage is implemented.The level of complexity of TOP
studieslassessments will vary depending the type and number of simultaneous outages and
on the unique challenges and reliability issues posed by the outages.It is left to the judgment
of the TOP to determine what level of analysis is appropriate for a given planned outage
situation.TOPs are responsible for determining how far to stress their system to identify or
rule out instability risks for the planned outage conditions.When determining how far to stress
the system during planned outage conditions,TOPs should follow the guidance provided in
the System Stressing Methodology section of the SOL Methodology.
While many planned outages require the development and implementation of outage specific
Operating Plans to facilitate a given planned outage,some outages may also require the
development of an IROL to facilitate the outage.
When planned outage studies indicate that,at reasonable and realistic maximum stressed
conditions during the planned outage(s),a single P1 Contingency or a credible MC results in
instability,Cascading or uncontrolled separation as described in the SOL Methodology,an
IROL is warranted for that planned outage.
IROLs and Risk Managementfor Local,Contained InstabilityImpacts
When IROLs are established,the current set of NERC Reliability Standards require that
System Operators take action up to and including shedding load to prevent exceeding that
IROL.There may be planned or forced outage scenarios where the system is vulnerable to
localized,contained instability.In prior outage scenarios where there are local,contained
instability impacts,the severity and extent of the instability impact may represent an
acceptable level of risk that may not warrant extreme operator action such as pre-Contingency
load shedding to prevent the instability from occurring in response to a Contingency event.
When such scenarios are determined to represent an acceptable level of risk,the local,
contained instability risk may be managed via an Operating Plan that does not include the use
of an IROL and does not include pre-Contingency load shedding.
Process for Determining Acceptable Levels of Risk for IROL Determination
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When prior outage studies indicate that a localized,contained area of the power system is at
risk of instability in response to the next worst single P1 Contingency or credible MC:
27.TOPs must determine the mitigations and a corresponding stability limit that would
be required to prevent that Contingency from resulting in localized,contained
instability.The stability limit would be expressed as a maximum flow value on a
monitored interface,cutplane or import bubble for the conditions under study.
28.When studies indicate that all other mitigations have been exhausted and pre-
Contingency load shedding is the only option remaining to prevent the Contingency
from resulting in localized,contained instability,TOPs must determine the amount
and location of load that must be shed pre-Contingency (at peak load for the period
under study)to prevent the Contingency from resulting in localized,contained
instability.
29.TOPs must determine the amount of load (at peak for the period under study)that is
at risk of being lost due to instability in response to the Contingency.This
assessment should include a determination of the physical and electrical extent of
expected instability (e.g.,the specific station buses that are expected to experience
voltage instability,the expected voltage levels at adjacent stations that represent the
boundary of impact).The assessment should also include any relay action that is
expected to occur that might isolate that area of impact.
30.If the amount of pre-Contingency load shedding required to prevent the Contingency
from resulting in localized,contained instability (as determined in item 28)is
relatively high compared to the amount of load that is at risk due to instability (as
determined in item 29),then the TOP must collaborate with the RC to determine the
levels of acceptable risk and to create an Operating Plan that addresses the
instability risk commensurate with those decisions.Accordingly,the Operating Plan
might not include steps for pre-Contingency load shedding,depending on the risk
management issues at hand.A key objective is to ensure that the mitigations
prescribed in the Operating Plan are consistent with good utility practice.
31.If it is determined that the localized,contained instability represents an unacceptable
level of risk,and pre-Contingency load shedding is warranted to prevent the
Contingency from resulting in the local,contained instability,then an IROL should be
established to prevent the Contingency from resulting in the localized,contained
instability.In such scenarios,the IROL will be based on the stability limit determined
in item 27,and the IROL Operating Procedure will be based on the information
determined in item 28.
Transient StabilityIROLs
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A transient stability IROL is established to prevent a single P1 Contingency or a credible MC
from resulting in either:
32.The loss of synchronism (from rotor angle instability or associated relay action)that
results in subsequent uncontrolled tripping of BES Facilities (Cascading),or in
uncontrolled separation as described in the SOL Methodology.
33.Widespread voltage collapse that occurs in the transient timeframe.
A transient stability IROL is not warranted to prevent one or more units from losing
synchronism and tripping offline,provided that studies demonstrate that the transmission
system remains stable after the units are lost.
Voltage StabilityIROLs
A voltage stability IROL is established to prevent a single P1 Contingency or a credible MC
from resulting in:
34.An undeterminable area or a wide area of the BES experiencing voltage instability
35.Voltage instability that consequently leads to Cascading or uncontrolled separation
Voltage stability IROLs are determined from transient and post-transient analysis methods,
techniques and assumptions as described in the SOL Methodology.
Facility Ratinq-Based IROLs
Facility Rating-based IROLs are established when studies show that a Contingency results in
excessive loading on a Facility,which triggers a chain reaction of Facility disconnections by
relay action,equipment failure or forced immediate manual disconnection of the Facility (for
example,due to line sag or public safety concerns),consistent with the NERC definition of
Cascading.The Cascading test is used to determine Cascading based on available Facility
Ratings.Facility Rating-based IROLs prevent non-stability related Cascading due to excessive
post-Contingency loading of Facilities [NERC Standard FAC-011-3 R3.7].While such IROLs
may be established as long-term IROLs for N-1-1 or N-1-2 operations,they may also be
established for credible MCs,or planned outage conditions to address the next worst single
P1 Contingency or the next worst credible MC.
For Facility Rating-based IROLs,the IROL will exist on the initial excessively loaded Facility
that is expected to be disconnected by automatic or manual action,leading to Cascading.The
IROL value will be the lesser of the relay trip setting or 125 percent of the Emergency Rating.
These IROLs will be monitored for their performance in the post-Contingency state through
RTAs.
Credible MC (Example 1):
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Studies show that credible MC X results in Facility Z loading up to or beyond the lower of the
relay trip setting or 125 percent of its Emergency Rating.Cascading tests indicate that the MC
X would result in Cascading.An IROL is established to prevent MC X from resulting in
Cascading.
36.The IROL is in effect when it becomes a risk to reliability.For planned outage
conditions,the IROL may be in effect during the planned outage.Otherwise,the
IROL may need to be in effect at all times.
37.The IROL exists on the initial excessively loaded Facility that is expected to be
disconnected by automatic or manual action,leading to Cascading.Accordingly,the
IROL is the MVA value on Facility Z that results exceeding the lower of the relay trip
setting or 125 percent of its Emergency Rating.
38.The IROL is monitored as the calculated post-Contingency flow on Facility Z in
response to MC X.
39.The IROL is exceeded when Real-time Assessments indicate that MC X results in
flow on Facility Z exceeding the lower of its trip setting or 125 percent of its
Emergency Rating.
Lonq-term N-1-1 Facility Ratinq Based IROL (Example 2):
"All transmission Facilities in service"studies show that the loss of Facility X is expected to
render the system in a position where a subsequent Contingency on Facility Y would result in
Facility Z loading up to or beyond the lower of the relay setting or 125 percent of its
Emergency Rating.Cascading tests indicate that the loss of Facility X followed by a
subsequent Contingency on Facility Y (with no system adjustments between Contingencies)
would result in Cascading,i.e.that the loss of line X would render the system in an N-1
insecure state for Contingency Y.An IROL is established to prevent the loss of Facility X,
followed by a Contingency of Facility Y,from resulting in Cascading.
40.The IROL exists on the initial excessively loaded Facility that is expected to be
disconnected by automatic or manual action,leading to Cascading.Accordingly,the
IROL is the MVA value on Facility Z that results in its tripping,in this case it is 125
percent of its Emergency Rating.
41.The IROL is monitored as the calculated post-Contingency flow on Facility Z for the
loss of Facility Y.
42.The IROL is not in effect unless there is a forcedlurgent outage or Contingency of
Facility X.The IROL becomes effective when Facility X experiences a forcedlurgent
outage.
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43.The IROL is exceeded when there is a forcedlurgent outage on Facility X,and
subsequent Real-time Assessments indicate that a Contingency of Facility Y results
in flow on Facility Z exceeding the lower of its relay trip setting or 125 percent of its
Emergency Rating.
U.IROL Tv in the Peak RC Area
The IROL Tv in the Peak RC Area shall be less than or equal to 30 minutes [FAC-011-3 R3.7].
The default IROL Tv value is 30 minutes.However,shorter duration IROL Tv values may be
established in coordination with the impacted TOPs based on relaylprotection settings and
other considerations.
V.Peak's Process for Addressing IROLs Established by Planning
Coordinators (PC)and Transmission Planners (TP)
FAC-014-2 Requirements R3 and R4 require PCs and TPs to establish SOLs and IROLs for
its PC or TP area consistent with its PC's SOL Methodology for the planning horizon.
Requirements R5.3 and R5.4 require PCs and TPs to communicate those SOLs and IROLs to
its RC.
Peak implements the following process for each IROL identified by the PC or TP pursuant to
the requirements in FAC-014-2:
1.Peak communicates with the PCITP to understand the nature of the IROL,the
assessments performed,the Contingencies that are associated with the IROL and
the criteria used in the analysis.
2.Peak applies the methodology and criteria in Peak's SOL Methodology for potential
IROL establishment for use in the Operations Horizon.This may require Peak to
perform additional studies in collaboration with the associated TOPs,taking into
consideration input from the PCITP.
3.Peak establishes IROLs based on the results of this collaboration.
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W.Peak's Role In Ensuring SOLs are Established Consistent with the
SOL Methodology
FAC-014-2 Requirement R1 requires the RC to ensure that SOLs and IROLs for its RC Area
are established and that the SOLs and IROLs are consistent with its SOL Methodology.Peak
performs the following functions to meet this requirement [NERC Standard FAC-014-2 R1]:
1.Peak ensures that Facilities in the West-wide System Model (WSM),which is Peak's
Energy Management System (EMS)model,are associated with the Facility Ratings
as provided by TOPs,consistent with this SOL Methodology.
2.Peak performs a coordination and facilitation role in the seasonal planning process,
and has a predominant role in the IRO-017 Outage Coordination Process for the RC
Area.
3.Peak ensures that buses in the WSM are associated with the System Voltage Limits
as provided by TOPs,consistent with this SOL Methodology.
4.Peak reviews the stability limitations provided by TOPs to ensure they are
established consistent with the SOL Methodology.Peak makes a final determination
whether the stability limitations are declared an actual IROL.
5.Peak ensures RC System Operators and engineers have awareness of identified
stability limitations and IROLs.
6.Peak performs Real-time monitoring and RTAs to determine SOL exceedances and
to determine if the system has unexpectedly entered into an N-1 or credible N-2
insecure state.If the system has unexpectedly entered into an N-1 or credible N-2
insecure state,Peak mitigates this condition within 30 minutes per internal Operating
Plans.
7.Peak's Real-time Contingency Analysis (RTCA)application provides indication of
whether acceptable thermal and voltage system performance is being achieved for
the post-Contingency state given actual system conditions.Peak posts its RTCA
results in the secure area of the PeakRC.org website for review by TOPs.If a TOP
notices any issues with the posted results,the TOP should coordinate with the RC to
havethoseissuesaddressed.
8.Peak utilizes a Real-time Voltage Stability Analysis (VSA)tool and communicates the
results of this tool to impacted TOPs.
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X.System Study Models [NERC Standard FAC-011-3 R3.4]
The Peak RC Area covers the entire Western Interconnection,less Alberta,and contains
several intra-regional DC transmission lines.However,except with Alberta,the Peak RC Area
is not connected synchronously with other RC Areas.Interregional DC lines tie Peak RC to its
RC neighbors.
While Facility Ratings and System Voltage Limits may not require a TOP study for their
establishment,stability limitations are identified as a direct result of system studies.TOPs
within the Peak RC Area generally use any of three study models for identifying instability
risks and establishing stability limitations:their respective EMS models,Peak's WSM,and off-
line models based on approved WECC operating base cases.Development of the WECC
operating base cases is coordinated by the WECC Regional Entity.The cases for each
season are approved by the WECC Regional Entity.
Peak uses both the WSM and the WECC operating base cases when performing system
studies.The WSM uses a network model of the entire Western Interconnection BES.While
the model contains some detail for non-BES Facilities,such as lower voltage generation
models and the sub-100 kV elements identified by the TOPs to impact the BES,much of the
system at these lower transmission voltages is reduced to a mathematical equivalent.Loads
served over radial lines are typically lumped at the delivery bus.The WSM consists of
transmission lines,transformers,circuit breakers and switches,reactive devices,generation
units,step-up transformers,loads and other relevant electrical components.
Though the WECC operating base case is not a breaker-to-breaker model,it consists of
similar information as mentioned above as well as additional details and modeling information
necessary to perform dynamic and transient stability studies.
1.TOPs and the RC shall use study models that include the entire Peak RC Area for
establishing stability limitations [NERC Standard FAC-011-3 R3.1].The study model
must include any critical modeling details from other RC Areas that would impact the
Facility(ies)under study.That said,it is acceptable to use models that equivalence
portions of the Peak RC Area's full loop model,provided that doing so does not
impede capturing interactions between the TOP Area and the external systems or
vice versa.
Y.TOP Communication of SOLs to Peak
This SOL Methodology contains several requirements for TOPs to communicate SOL
information to Peak "per the RC Instructions."These RC instructions are maintained outside of
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the SOL Methodology to provide the flexibility needed for modification without having to revise
the SOL Methodology.
The RC instructions referenced in the SOL Methodology are posted in the secured area of
PeakRC.org website.
Z.RC Communication of SOL and IROL Information to Other
Functional Entities
Peak provides SOLs and IROLs to those entities listed below that have provided a written
request that includes a schedule for delivery of those limits [NERC Standard FAC-014-2 R5].
These entities include [NERC Standard FAC-014-2 R.5.1]:
1.Adjacent Reliability Coordinators and Reliability Coordinators with a reliability-related
need for those limits
2.Transmission Operators within the Peak RC Area
3.Transmission Planners within the Peak RC Area
4.Transmission Service Providers within the Peak RC Area
5.Planning Authorities/Planning Coordinators within the Peak RC Area
Peak provides the following supporting information for each IROL as part of the corresponding
IROL Operating Procedure:
6.Identification and status information of the associated Facility (or group of Facilities)
that is critical to the derivation of the IROL [NERC Standard FAC-014-2 R5.1.1]
7.The value of the IROL and its associated Tv [NERC Standard FAC-014-2 R5.1.2]
8.The associated Contingency(ies)[NERC Standard FAC-014-2 R5.1.3]
9.The type of limitation represented by the IROL (e.g.,voltage collapse,transient
stability)[NERC Standard FAC-014-2 R5.1.4]
Contact Information
For information about the Peak RC SOL Methodology for the Operations Horizon,or if you
have any questions,please contact [e-mail].
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Version History
Version Date Action By Change Tracking
1.0 01/01/2009 Issued for Original procedure
implementation
2.0 07/08/2009 Revised Reformatting
3.0 10/30/2009 Revised Multiple Contingency Criteria
changes
4.0 02/04/2010 Revised WECC RC format.Classification
changed to external
5.0 10/27/2011 Revised Changed classification to "Public"
6.0 01/23/2012 Revised Vic Howell Major Revision
WECC RC SOL
Methodology Phase I
project
6.1.04/02/2012 Revised Vic Howell Changed effective date to
6/4/2012
Corrected typo in BES
Performance Requirements
section
Minor change in WECC RC
System and System Models
section
7.0 08/30/2013 Revised Jaison Major Revision
Tsikirai Peak RC SOL Methodology
Phase Il project
Merged the SOL
Methodology with the
"Establish and
Communicate SOLs"
Version 3.1 procedure
Document 'Peaked'
following the 2/12/14 FERC
approval of bifurcation.No
version change.No issue
date change.Effective date
remains the same.
7.1 5/4/2016 Revised Vic Howell Address FERC Settlement issues
and minor corrections.Effective
immediately upon release.
8.0 1/13/2017 Revised Vic Howell Major Revision
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Better aligns with new TOP
and IRO standards
Implements concepts in the
NERC SOL White Paper
Implements Path Operator
Task Force (POTF)
Recommendation
8.1 2/24/2017 Revised Vic Howell Minor Revision
Addressed retirement of
TOP-007-WECC-1a
Reliability Standard in
Section K
Corrected minor typos
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AppendixA
Terms Used in the SOL Methodologyfor the Operations Horizon
Terms used as defined/described in the SOL Methodologyfor the Operations Horizon:
Always Credible Multiple Contingency -A multiple Contingency (MC)that,based on historical
performance and TOP risk assessments,have a sufficiently high degree of likelihood of
occurrence such that the TOP determines that the MC should be protected against in all phases
of the operations planning process and in Real-time operations.
Conditionally Credible Multiple Contingency -A multiple Contingency (MC)whose credibility is
a function of observable system conditions.
Operations Horizon -A rolling 12-month period starting at Real-time (now)through the last hour
of the twelfth month into the future.
Operational Transfer Capability (OTC)-(from the retired WECC standard TOP-STD-007-0):
The OTC is the maximum amount of actual power that can be transferred over direct or parallel
transmission elements comprising:
An interconnection from one Transmission Operator area to another Transmission
Operator area;or
A transfer Path within a Transmission Operator area.
System Voltaqe Limit -The maximum and minimum steady-state voltage limits (both normal
and emergency)that provide for acceptable System performance.
Terms used as defined in the NERC Glossary of Terms:
The following list of terms from the NERC Glossary of Terms are used in the SOL Methodology.
The definitions from the NERC Glossary of Terms are not included here.Please reference the
NERC Glossary for the definitions.
Bulk Electric System (BES)
Cascading
Contingency
Corrective Action Plan
Element
Emergency Rating
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Facility
Facility Rating
Fault
Interconnection Reliability Operating Limit (IROL)
Near-Term Transmission Planning Horizon
Normal Clearing
Normal Rating
Operating Plans
Operational Planning Analysis (OPA)
Operating Procedure
Operating Process
Planning Assessment
Real-time
Real-time Assessments (RTA)
Reliability Coordinator (RC)Area
Remedial Action Scheme (RAS)
System
System Operating Limit (SOL)
System Operator
Total Transfer Capability
Transfer Capability
Transmission Operator (TOP)Area
Undervoltage Load Shedding (UVLS)Program
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AppendixB
Dampinq Ratio Calculation Example
Measuring damping is best performed a)after all significant automatic schemes have operated;
and b)should measure damping over oscillations toward the end of the simulation rather than at
the beginning of the simulation.As an example,a good trigger for measuring signal damping
during a ten-second run is about two seconds after the fault clears as most automatic schemes
have switched and the fault should be fully cleared.
O 2
0.15
O 1
O05 '
-O 1
-0.15
-O.2
-O.25 O O.1 0.2 O.3 O.4 O.5 O.6 O.7 O.8 O.9 1 1.1 1.2 1.3 1.4 1.5 1.6
1 'Xo'Log-dec is derived from ratio:S :=-ln -
11 Xii 5 =0.305
Note that the approximateformula =6 /(2·x )=0.049 × 100 =4.9%damping ratio
Where n =Number of periods between measurement Xo and measurement Xn
Periods =5 in example
Xo is magnitude of oscillation at first measurement
Xn is magnitude of oscillation at second measurement
Ln =log in base e
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Appendix C
Use of Automatic Schemes
NOTE:This table is intended to summarize and reflect the languagein the Allowed Uses of Automatic Mitigation Schemes in the OperationsHorizon section of the SOLMethodology.If discrepanciesare perceivedto exist between the table and the languagein the SOL Methodology,the languagein the SOL Methodologyshall prevail.
NOTE:For every YES:Studies must show reliability issues are resolved.If any automatic scheme does not perform as designed,causes reliability issues or is
expected to be unavailable,an Operating Plan with pre-Contingencymitigation actions must address reliability issues.
Contingencyresults indicate system ...Contingency results mdicate system instability,Cascading,orstability,no Cascading,and no un-uncontrolled separationcontrolledseparation
Non-outage Outage Conditions Non-outageConditions Outage ConditionsConditions
Always Credible Always CredibleSingleSingleSingleSingle
.and Conditionally and ConditionallyContingencyContingencyContmgencyCredibleMC1ContingencyCredibleMC1
Use of non-load-shed YES YES Use of non-load-shed YES YES YES YES
automatic schemes automatic schemes
allowed?allowed?(no singlepointoffailureallowed)
Use of load-shed YES2,3 YES2,3,4 Use of load-shed YES2,3 YES YES2,3,4 YES
automatic schemes automatic schemesdesignedforspecificdesignedforspecificContingenciesContingencies
allowed?allowed?(no singlepointoffailureallowed)
*Note that automatic schemes that are intended and designed to address certain non-credible MCs (including extreme event Contingencies)are allowed to be relied upon to meet
their intended design objectives for those non-credible and extreme event Contingencies;however,the SOL Methodology does not require assessment of -and therefore,
determination of acceptable performance for -non-credible and extreme event Contingencies in the Operations Horizon.
2 Load-shed schemes may be relied upon and utilized in operations for single P1 Contingencies if the scheme's impact is limited to a small amount of load in the local network area
per their design according to the allowances in Table 1 of TPL-001-4 for single P1 Contingencies.3TOPs are expected to take action up to,but not necessarily including pre-Contingency load shedding to,if at all possible,pre-position (or re-position)the system to avoid reliance
on the load shed scheme.
4 Applies when the planned or forced outage makes the specific credible MC in the planning horizon,for which the load-shed automatic scheme was designed,become a single
Contingency in the operations horizon.
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