COORDONNATEUR
DE LA FIABILITÉ
Demande R-3699-2009
Direction Contrôle des mouvements d’énergie
NORMES DE FIABILITÉ DE LA NERC - FAC
(VERSION ANGLAISE)
Original : 2013-03-27
HQCMÉ-8, Document 2.3
(En liasse)
Standard FAC-001-0 — Facility Connection Requirements
A.
Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0
3.
Purpose: To avoid adverse impacts on reliability, Transmission Owners must establish
facility connection and performance requirements.
4.
Applicability:
4.1.
5.
B.
Transmission Owner
Effective Date:
April 1, 2005
Requirements
R1. The Transmission Owner shall document, maintain, and publish facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability Organization, subregional, Power Pool, and individual Transmission Owner
planning criteria and facility connection requirements. The Transmission Owner’s facility
connection requirements shall address connection requirements for:
R1.1. Generation facilities,
R1.2. Transmission facilities, and
R1.3. End-user facilities
R2. The Transmission Owner’s facility connection requirements shall address, but are not limited
to, the following items:
R2.1. Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Procedures for coordinated joint studies of new facilities and their impacts on
the interconnected transmission systems.
R2.1.2. Procedures for notification of new or modified facilities to others (those
responsible for the reliability of the interconnected transmission systems) as
soon as feasible.
R2.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
R2.1.4. Breaker duty and surge protection.
R2.1.5. System protection and coordination.
R2.1.6. Metering and telecommunications.
R2.1.7. Grounding and safety issues.
R2.1.8. Insulation and insulation coordination.
R2.1.9. Voltage, Reactive Power, and power factor control.
R2.1.10. Power quality impacts.
R2.1.11. Equipment Ratings.
R2.1.12. Synchronizing of facilities.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
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Standard FAC-001-0 — Facility Connection Requirements
R2.1.13. Maintenance coordination.
R2.1.14. Operational issues (abnormal frequency and voltages).
R2.1.15. Inspection requirements for existing or new facilities.
R2.1.16. Communications and procedures during normal and emergency operating
conditions.
R3. The Transmission Owner shall maintain and update its facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Reliability Organization, and NERC on
request (five business days).
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R1.
M2. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all requirements stated in Reliability Standard FAC-001-0_R2.
M3. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R3.
D.
Compliance
1.
2.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
1.2.
Compliance Monitoring Period and Reset Timeframe
On request (five business days).
1.3.
Data Retention
None specified.
1.4.
Additional Compliance Information
None.
Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
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Standard FAC-001-0 — Facility Connection Requirements
2.4.
E.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
3 of 3
Standard FAC-001-0 — Facility Connection Requirements
Appendix QC-FAC-001-0
Provisions specific to the standard FAC-001-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.This appendix
establishes specific provisions for the application of the standard in Québec and is an integral part of the
standard. Provisions of the standard and of its appendix must be read jointly for comprehension and
interpretation purposes. If there should happen to be an interpretation question between the standard and
its appendix, the present appendix shall take precedence over the standard provisions.
A.
B.
Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0
3.
Purpose:
No specific provision
4.
Applicability:
No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l’énergie: Month July 25,xx 2012x
5.2.
Adoption of the appendix by the Régie de l’énergie: Month July 25,xx 2012x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
E.
Regional Differences
No specific provision
Adopted by the Régie de l’énergie (Décision D-2012x-091xxxx): JulyMonth 25xx, 2012x
Page QC-1 of 2
Standard FAC-001-0 — Facility Connection Requirements
Appendix QC-FAC-001-0
Provisions specific to the standard FAC-001-0 applicable in Québec
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Adopted by the Régie de l’énergie (Décision D-2012x-091xxxx): JulyMonth 25xx, 2012x
Change Tracking
New
Page QC-2 of 2
Standard FAC-002-1 — Coordination of Plans for New Facilities
A.
Introduction
1.
Title:
Facilities
Coordination of Plans For New Generation, Transmission, and End-User
2.
Number:
FAC-002-1
3.
Purpose: To avoid adverse impacts on reliability, Generator Owners and Transmission
Owners and electricity end-users must meet facility connection and performance requirements.
4.
Applicability:
5.
B.
4.1.
Generator Owner
4.2.
Transmission Owner
4.3.
Distribution Provider
4.4.
Load-Serving Entity
4.5.
Transmission Planner
4.6.
Planning Authority
(Proposed) Effective Date: The first day of the first calendar quarter six months after
applicable regulatory approval; or in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter six months after Board of Trustees’
adoption.
Requirements
R1. The Generator Owner, Transmission Owner, Distribution Provider, and Load-Serving Entity
seeking to integrate generation facilities, transmission facilities, and electricity end-user
facilities shall each coordinate and cooperate on its assessments with its Transmission Planner
and Planning Authority. The assessment shall include:
1.1.
Evaluation of the reliability impact of the new facilities and their connections on the
interconnected transmission systems.
1.2.
Ensurance of compliance with NERC Reliability Standards and applicable Regional,
subregional, Power Pool, and individual system planning criteria and facility
connection requirements.
1.3.
Evidence that the parties involved in the assessment have coordinated and cooperated
on the assessment of the reliability impacts of new facilities on the interconnected
transmission systems. While these studies may be performed independently, the
results shall be jointly evaluated and coordinated by the entities involved.
1.4.
Evidence that the assessment included steady-state, short-circuit, and dynamics studies
as necessary to evaluate system performance under both normal and contingency
conditions in accordance with Reliability Standards TPL-001-0, TPL-002-0, and TPL003-0.
1.5.
Documentation that the assessment included study assumptions, system performance,
alternatives considered, and jointly coordinated recommendations.
R2. The Planning Authority, Transmission Planner, Generator Owner, Transmission Owner, LoadServing Entity, and Distribution Provider shall each retain its documentation (of its evaluation
of the reliability impact of the new facilities and their connections on the interconnected
Adopted by Board of Trustees: August 5, 2010
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
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Standard FAC-002-1 — Coordination of Plans for New Facilities
transmission systems) for three years and shall provide the documentation to the Regional
Reliability Organization(s) and NERC on request (within 30 calendar days).
C.
Measures
M1. The Planning Authority, Transmission Planner, Generator Owner, Transmission Owner, LoadServing Entity, and Distribution Provider’s documentation of its assessment of the reliability
impacts of new facilities shall address all items in Reliability Standard FAC-002-0_R1.
M2. The Planning Authority, Transmission Planner, Generator Owner, Transmission Owner, LoadServing Entity, and Distribution Provider shall each have evidence of its assessment of the
reliability impacts of new facilities and their connections on the interconnected transmission
systems is retained and provided to other entities in accordance with Reliability Standard
FAC-002-0_R2.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Regional Entity.
1.2.
Compliance Monitoring Period and Reset Timeframe
Not applicable.
1.3.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
2.
E.
1.4.
Data Retention
Evidence of the assessment of the reliability impacts of new facilities and their
connections on the interconnected transmission systems: Three years.
1.5.
Additional Compliance Information
None
Violation Severity Levels (no changes)
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
January 13, 2006
Removed duplication of “Regional Reliability
Organizations(s).
Errata
1
TBD
Modified to address Order No. 693 Directives
contained in paragraph 693.
Revised.
Adopted by Board of Trustees: August 5, 2010
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
2 of 2
Standard FAC-002-1 — Coordination of Plans for New Facilities
Appendix QC-FAC-002-1
Provisions specific to the standard FAC-002-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
User Facilities
Coordination of Plans For New Generation, Transmission, and End-
2.
Number:
FAC-002-1
3.
Purpose:
No specific provision
4.
Applicability:
No specific provision
4.1.Functions: No specific provision
4.2.Facilities: No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie: Month xx, 201x
5.2.
Adoption of the appendix by the Régie: Month xx, 201x
5.3.Effective date of the standard and its appendix in Québec: Month xx, 201x
5.3.
B.
Scope: No specific provision
Requirements
R1. No specific provision
R1.1. No specific provision
R1.2. No specific provision
R1.3. No specific provision
R1.4. Evidence that the assessment included steady-state, short-circuit, and dynamics studies
as necessary to evaluate system performance under both normal and contingency
conditions in accordance with Reliability Standards TPL-001-0, TPL-002-0, and TPL003-0. For facilities that are not par of the Bulk Power System, compliance with
standards TPL-001-0, TPL-002-0 and TPL-003-0 is not required.
R1.5. No specific provision
R2. No specific provision
C.
Measures
M1. Read “Reliability Standard FAC-002-1”
M2. Read “Reliability Standard FAC-002-1”
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 4
Standard FAC-002-1 — Coordination of Plans for New Facilities
Appendix QC-FAC-002-1
Provisions specific to the standard FAC-002-1 applicable in Québec
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
The Régie de l’énergie is responsible, in Québec, for compliance enforcement with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3.
Compliance Monitoring and Enforcement Processes
No specific provision
1.4.
Data Retention
No specific provision
1.5.
Additional Compliance Information
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-2 of 4
Standard FAC-002-1 — Coordination of Plans for New Facilities
Appendix QC-FAC-002-1
Provisions specific to the standard FAC-002-1 applicable in Québec
2.
Violation Severity Levels
Requirement
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The responsible entity failed
to include in its assessment
one of the subcomponents
(R1.1 to R1.5).
The responsible entity failed
to include in its assessment
two of the subcomponents
(R1.1 to R1.5).
The responsible entity failed
to include in its assessment
three of the subcomponents
(R1.1 to R1.5).
The responsible entity failed
to include in its assessment
four of the subcomponents
(R1.1 to R1.5).
R1.1.
N/A
N/A
N/A
N/A
R1.2.
N/A
N/A
N/A
N/A
R1.3.
N/A
N/A
N/A
N/A
R1.4.
N/A
N/A
N/A
N/A
R1.5.
N/A
N/A
N/A
N/A
R2.
The responsible entity
provided the documentation
more than 30 calendar days,
but less than or equal to 40
calendar days, after a
request.
The responsible entity
provided the documentation
more than 40 calendar days,
but less than or equal to 50
calendar days, after a
request.
The responsible entity
provided the documentation
more than 50 calendar days,
but less than or equal to 60
calendar days, after a
request.
The responsible entity
provided the documentation
more than 60 calendar days
after a request or was unable
to provide the documentation
for the required three-year
period.
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-3 of 4
Standard FAC-002-1 — Coordination of Plans for New Facilities
Appendix QC-FAC-002-1
Provisions specific to the standard FAC-002-1 applicable in Québec
No specific provision
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Change Tracking
New
Page QC-4 of 4
Standard FAC-003-1 — Transmission Vegetation Management Program
A.
B.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-1
3.
Purpose: To improve the reliability of the electric transmission systems by preventing
outages from vegetation located on transmission rights-of-way (ROW) and minimizing
outages from vegetation located adjacent to ROW, maintaining clearances between
transmission lines and vegetation on and along transmission ROW, and reporting vegetationrelated outages of the transmission systems to the respective Regional Reliability
Organizations (RRO) and the North American Electric Reliability Council (NERC).
4.
Applicability:
4.1. Transmission Owner.
4.2. Regional Reliability Organization.
4.3. This standard shall apply to all transmission lines operated at 200 kV and above and to
any lower voltage lines designated by the RRO as critical to the reliability of the
electric system in the region.
5.
Effective Dates:
5.1.
One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.
Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.
Requirements
R1. The Transmission Owner shall prepare, and keep current, a formal transmission vegetation
management program (TVMP). The TVMP shall include the Transmission Owner’s
objectives, practices, approved procedures, and work specifications1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the Transmission Owner’s transmission lines.
R1.2. The Transmission Owner, in the TVMP, shall identify and document clearances
between vegetation and any overhead, ungrounded supply conductors, taking into
consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway. Specifically, the Transmission Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The Transmission Owner shall determine and document
appropriate clearance distances to be achieved at the time of transmission
vegetation management work based upon local conditions and the expected
time frame in which the Transmission Owner plans to return for future
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
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Standard FAC-003-1 — Transmission Vegetation Management Program
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The Transmission Owner shall determine and document
specific radial clearances to be maintained between vegetation and conductors
under all rated electrical operating conditions. These minimum clearance
distances are necessary to prevent flashover between vegetation and
conductors and will vary due to such factors as altitude and operating voltage.
These Transmission Owner-specific minimum clearance distances shall be no
less than those set forth in the Institute of Electrical and Electronics Engineers
(IEEE) Standard 516-2003 (Guide for Maintenance Methods on Energized
Power Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner, to
perform their duties.
R1.4. Each Transmission Owner shall develop mitigation measures to achieve sufficient
clearances for the protection of the transmission facilities when it identifies locations
on the ROW where the Transmission Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner shall establish and document a process for the immediate
communication of vegetation conditions that present an imminent threat of a
transmission line outage. This is so that action (temporary reduction in line rating,
switching line out of service, etc.) may be taken until the threat is relieved.
R2. The Transmission Owner shall create and implement an annual plan for vegetation
management work to ensure the reliability of the system. The plan shall describe the methods
used, such as manual clearing, mechanical clearing, herbicide treatment, or other actions. The
plan should be flexible enough to adjust to changing conditions, taking into consideration
anticipated growth of vegetation and all other environmental factors that may have an impact
on the reliability of the transmission systems. Adjustments to the plan shall be documented as
they occur. The plan should take into consideration the time required to obtain permissions or
permits from landowners or regulatory authorities. Each Transmission Owner shall have
systems and procedures for documenting and tracking the planned vegetation management
work and ensuring that the vegetation management work was completed according to work
specifications.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
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Standard FAC-003-1 — Transmission Vegetation Management Program
R3. The Transmission Owner shall report quarterly to its RRO, or the RRO’s designee, sustained
transmission line outages determined by the Transmission Owner to have been caused by
vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The Transmission Owner is not required to report to the RRO, or the RRO’s designee,
certain sustained transmission line outages caused by vegetation: (1) Vegetationrelated outages that result from vegetation falling into lines from outside the ROW that
result from natural disasters shall not be considered reportable (examples of disasters
that could create non-reportable outages include, but are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind shear, major storms as defined either by
the Transmission Owner or an applicable regulatory body, ice storms, and floods), and
(2) Vegetation-related outages due to human or animal activity shall not be considered
reportable (examples of human or animal activity that could cause a non-reportable
outage include, but are not limited to, logging, animal severing tree, vehicle contact
with tree, arboricultural activities or horticultural or agricultural activities, or removal
or digging of vegetation).
R3.3. The outage information provided by the Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum: the name of the circuit(s) outaged, the
date, time and duration of the outage; a description of the cause of the outage; other
pertinent comments; and any countermeasures taken by the Transmission Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
R4. The RRO shall report the outage information provided to it by Transmission Owner’s, as
required by Requirement 3, quarterly to NERC, as well as any actions taken by the RRO as a
result of any of the reported outages.
C.
Measures
M1. The Transmission Owner has a documented TVMP, as identified in Requirement 1.
M1.1. The Transmission Owner has documentation that the Transmission Owner performed
the vegetation inspections as identified in Requirement 1.1.
M1.2. The Transmission Owner has documentation that describes the clearances identified in
Requirement 1.2.
M1.3. The Transmission Owner has documentation that the personnel directly involved in the
design and implementation of the Transmission Owner’s TVMP hold the qualifications
identified by the Transmission Owner as required in Requirement 1.3.
M1.4. The Transmission Owner has documentation that it has identified any areas not
meeting the Transmission Owner’s standard for vegetation management and any
mitigating measures the Transmission Owner has taken to address these deficiencies as
identified in Requirement 1.4.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
3 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
M1.5. The Transmission Owner has a documented process for the immediate communication
of imminent threats by vegetation as identified in Requirement 1.5.
M2. The Transmission Owner has documentation that the Transmission Owner implemented the
work plan identified in Requirement 2.
M3. The Transmission Owner has documentation that it has supplied quarterly outage reports to
the RRO, or the RRO’s designee, as identified in Requirement 3.
M4. The RRO has documentation that it provided quarterly outage reports to NERC as identified in
Requirement 4.
D.
Compliance
1.
2.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
RRO
NERC
1.2.
Compliance Monitoring Period and Reset
One calendar Year
1.3.
Data Retention
Five Years
1.4.
Additional Compliance Information
The Transmission Owner shall demonstrate compliance through self-certification
submitted to the compliance monitor (RRO) annually that it meets the requirements of
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an onsite audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
Levels of Non-Compliance
2.1.
Level 1:
2.1.1.
The TVMP was incomplete in one of the requirements specified in any
subpart of Requirement 1, or;
2.1.2.
Documentation of the annual work plan, as specified in Requirement 2, was
incomplete when presented to the Compliance Monitor during an on-site
audit, or;
2.1.3.
The RRO provided an outage report to NERC that was incomplete and did not
contain the information required in Requirement 4.
2.2. Level 2:
2.2.1.
The TVMP was incomplete in two of the requirements specified in any
subpart of Requirement 1, or;
2.2.2.
The Transmission Owner was unable to certify during its annual selfcertification that it fully implemented its annual work plan, or documented
deviations from, as specified in Requirement 2.
2.2.3.
The Transmission Owner reported one Category 2 transmission vegetationrelated outage in a calendar year.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
4 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
2.3. Level 3:
2.4.
E.
2.3.1.
The Transmission Owner reported one Category 1 or multiple Category 2
transmission vegetation-related outages in a calendar year, or;
2.3.2.
The Transmission Owner did not maintain a set of clearances (Clearance 2),
as defined in Requirement 1.2.2, to prevent flashover between vegetation
and overhead ungrounded supply conductors, or;
2.3.3.
The TVMP was incomplete in three of the requirements specified in any
subpart of Requirement 1.
Level 4:
2.4.1.
The Transmission Owner reported more than one Category 1 transmission
vegetation-related outage in a calendar year, or;
2.4.2.
The TVMP was incomplete in four or more of the requirements specified in
any subpart of Requirement 1.
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
Version 1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
5 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
Appendix QC-FAC-003-1
Provisions specific to the standard FAC-003-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.This appendix
establishes specific provisions for the application of the standard in Québec and is an integral part of the
standard. Provisions of the standard and of its appendix must be read jointly for comprehension and
interpretation purposes. If there should happen to be an interpretation question between the standard and
its appendix, the present appendix shall take precedence over the standard provisions.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-1
3.
Purpose:
No specific provision
4.
Applicability:
Functions
4.1.
No specific provision
4.2.
Not applicable in Québec
Facilities
4.3.
5.
B.
This standard shall apply to all transmission lines operated at 200 kV and above.
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx 201xJuly 25, 2012
5.2.
Adoption of the appendix by the Régie de l'énergie: July 25, 2012Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
Adopted by the Régie de l’énergie (Décision D-2012x-091xxxx): MonthJuly xx25, 2012x
Page QC-1 of 3
Standard FAC-003-1 — Transmission Vegetation Management Program
Appendix QC-FAC-003-1
Provisions specific to the standard FAC-003-1 applicable in Québec
No specific provision
2.
Levels of Non-Compliance
No specific provision
Adopted by the Régie de l’énergie (Décision D-2012x-091xxxx): MonthJuly xx25, 2012x
Page QC-2 of 3
Standard FAC-003-1 — Transmission Vegetation Management Program
Appendix QC-FAC-003-1
Provisions specific to the standard FAC-003-1 applicable in Québec
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Adopted by the Régie de l’énergie (Décision D-2012x-091xxxx): MonthJuly xx25, 2012x
Change Tracking
New
Page QC-3 of 3
Standard FAC-008-1 — Facility Ratings Methodology
A. Introduction
1.
Title:
Facility Ratings Methodology
2.
Number:
FAC-008-1
3.
Purpose:
To ensure that Facility Ratings used in the reliable planning and operation of the
Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Transmission Owner
4.2. Generator Owner
5.
Effective Date:
August 7, 2006
B. Requirements
R1.
The Transmission Owner and Generator Owner shall each document its current methodology
used for developing Facility Ratings (Facility Ratings Methodology) of its solely and jointly
owned Facilities. The methodology shall include all of the following:
R1.1.
A statement that a Facility Rating shall equal the most limiting applicable Equipment
Rating of the individual equipment that comprises that Facility.
R1.2.
The method by which the Rating (of major BES equipment that comprises a Facility)
is determined.
R1.2.1. The scope of equipment addressed shall include, but not be limited to,
generators, transmission conductors, transformers, relay protective devices,
terminal equipment, and series and shunt compensation devices.
R1.2.2. The scope of Ratings addressed shall include, as a minimum, both Normal
and Emergency Ratings.
R1.3.
Consideration of the following:
R1.3.1. Ratings provided by equipment manufacturers.
R1.3.2. Design criteria (e.g., including applicable references to industry Rating
practices such as manufacturer’s warranty, IEEE, ANSI or other standards).
R1.3.3. Ambient conditions.
R1.3.4. Operating limitations.
R1.3.5. Other assumptions.
R2.
The Transmission Owner and Generator Owner shall each make its Facility Ratings
Methodology available for inspection and technical review by those Reliability Coordinators,
Transmission Operators, Transmission Planners, and Planning Authorities that have
responsibility for the area in which the associated Facilities are located, within 15 business
days of receipt of a request.
R3.
If a Reliability Coordinator, Transmission Operator, Transmission Planner, or Planning
Authority provides written comments on its technical review of a Transmission Owner’s or
Generator Owner’s Facility Ratings Methodology, the Transmission Owner or Generator
Owner shall provide a written response to that commenting entity within 45 calendar days of
receipt of those comments. The response shall indicate whether a change will be made to the
Adopted by Board of Trustees: February 7, 2006
Effective Date: August 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
1 of 4
Standard FAC-008-1 — Facility Ratings Methodology
Facility Ratings Methodology and, if no change will be made to that Facility Ratings
Methodology, the reason why.
C. Measures
M1. The Transmission Owner and Generator Owner shall each have a documented Facility Ratings
Methodology that includes all of the items identified in FAC-008 Requirement 1.1 through
FAC-008 Requirement 1.3.5.
M2. The Transmission Owner and Generator Owner shall each have evidence it made its Facility
Ratings Methodology available for inspection within 15 business days of a request as follows:
M2.1
The Reliability Coordinator shall have access to the Facility Ratings Methodologies
used for Rating Facilities in its Reliability Coordinator Area.
M2.2
The Transmission Operator shall have access to the Facility Ratings Methodologies
used for Rating Facilities in its portion of the Reliability Coordinator Area.
M2.3
The Transmission Planner shall have access to the Facility Ratings Methodologies
used for Rating Facilities in its Transmission Planning Area.
M2.4
The Planning Authority shall have access to the Facility Ratings Methodologies used
for Rating Facilities in its Planning Authority Area.
M3. If the Reliability Coordinator, Transmission Operator, Transmission Planner, or Planning
Authority provides documented comments on its technical review of a Transmission Owner’s
or Generator Owner’s Facility Ratings Methodology, the Transmission Owner or Generator
Owner shall have evidence that it provided a written response to that commenting entity within
45 calendar days of receipt of those comments. The response shall indicate whether a change
will be made to the Facility Ratings Methodology and, if no change will be made to that
Facility Ratings Methodology, the reason why.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Transmission Owner and Generator Owner shall self-certify its compliance to the
Compliance Monitor at least once every three years. New Transmission Owners and
Generator Owners shall each demonstrate compliance through an on-site audit conducted
by the Compliance Monitor within the first year that it commences operation. The
Compliance Monitor shall also conduct an on-site audit once every nine years and an
investigation upon complaint to assess performance.
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
The Transmission Owner and Generator Owner shall each keep all superseded portions of
its Facility Ratings Methodology for 12 months beyond the date of the change in that
methodology and shall keep all documented comments on the Facility Ratings
Methodology and associated responses for three years. In addition, entities found noncompliant shall keep information related to the non-compliance until found compliant.
Adopted by Board of Trustees: February 7, 2006
Effective Date: August 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
2 of 4
Standard FAC-008-1 — Facility Ratings Methodology
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Transmission Owner and Generator Owner shall each make the following available
for inspection during an on-site audit by the Compliance Monitor or within 15 business
days of a request as part of an investigation upon complaint:
2.
1.4.1
Facility Ratings Methodology
1.4.2
Superseded portions of its Facility Ratings Methodology that had been replaced,
changed or revised within the past 12 months
1.4.3
Documented comments provided by a Reliability Coordinator, Transmission
Operator, Transmission Planner or Planning Authority on its technical review of
a Transmission Owner’s or Generator Owner’s Facility Ratings methodology,
and the associated responses
Levels of Non-Compliance
2.1. Level 1:
exists:
There shall be a level one non-compliance if any of the following conditions
2.1.1
The Facility Ratings Methodology does not contain a statement that a Facility
Rating shall equal the most limiting applicable Equipment Rating of the
individual equipment that comprises that Facility.
2.1.2
The Facility Ratings Methodology does not address one of the required
equipment types identified in FAC-008 R1.2.1.
2.1.3
No evidence of responses to a Reliability Coordinator’s, Transmission Operator,
Transmission Planner, or Planning Authority’s comments on the Facility Ratings
Methodology.
2.2. Level 2:
The Facility Ratings Methodology is missing the assumptions used to
determine Facility Ratings or does not address two of the required equipment types
identified in FAC-008 R1.2.1.
2.3. Level 3:
The Facility Ratings Methodology does not address three of the required
equipment types identified in FAC-008-1 R1.2.1.
2.4. Level 4:
The Facility Ratings Methodology does not address both Normal and
Emergency Ratings or the Facility Ratings Methodology was not made available for
inspection within 15 business days of receipt of a request.
E. Regional Differences
None Identified.
Version History
Version
1
Date
Action
Change Tracking
01/01/05
1.
01/20/05
2.
3.
Lower cased the word “draft” and
“drafting team” where appropriate.
Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
Changed “Timeframe” to “Time
Adopted by Board of Trustees: February 7, 2006
Effective Date: August 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
3 of 4
Standard FAC-008-1 — Facility Ratings Methodology
Frame” and “twelve” to “12” in item
D, 1.2.
Adopted by Board of Trustees: February 7, 2006
Effective Date: August 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
4 of 4
Standard FAC-008-1 — Facility Ratings Methodology
Appendix QC-FAC-008-1
Provisions specific to the standard FAC-008-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.This appendix
establishes specific provisions for the application of the standard in Québec and is an integral part of the
standard. Provisions of the standard and of its appendix must be read jointly for comprehension and
interpretation purposes. If there should happen to be an interpretation question between the standard and
its appendix, the present appendix shall take precedence over the standard provisions.
A.
B.
Introduction
1.
Title:
Facility Ratings Methodology
2.
Number:
FAC-008-1
3.
Purpose:
No specific provision
4.
Applicability:
No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx 201xJuly 25, 2012
5.2.
Adoption of the appendix by the Régie de l'énergie: July 25, 2012Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
Requirements
R1. No specific provision
R1.1. No specific provision
R1.2. The method by which the Rating (of major RTP equipment that comprises a Facility) is
determined.
R2. No specific provision
R3. No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
Adopted by the Régie de l’énergie (Déecision D-2012x-xxxx091): July 25, 2012Month xx, 201x Page QC-1 of 3
Standard FAC-008-1 — Facility Ratings Methodology
Appendix QC-FAC-008-1
Provisions specific to the standard FAC-008-1 applicable in Québec
No specific provision
2.
Levels of Non-Compliance
No specific provision
Adopted by the Régie de l’énergie (Déecision D-2012x-xxxx091): July 25, 2012Month xx, 201x Page QC-2 of 3
Standard FAC-008-1 — Facility Ratings Methodology
Appendix QC-FAC-008-1
Provisions specific to the standard FAC-008-1 applicable in Québec
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Change Tracking
New
Adopted by the Régie de l’énergie (Déecision D-2012x-xxxx091): July 25, 2012Month xx, 201x Page QC-3 of 3
Standard FAC-009-1 — Establish and Communicate Facility Ratings
A. Introduction
1.
Title:
Establish and Communicate Facility Ratings
2.
Number:
FAC-009-1
3.
Purpose:
To ensure that Facility Ratings used in the reliable planning and operation of the
Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Transmission Owner
4.2. Generator Owner
5.
Effective Date: October 7, 2006
B. Requirements
R1.
The Transmission Owner and Generator Owner shall each establish Facility Ratings for its
solely and jointly owned Facilities that are consistent with the associated Facility Ratings
Methodology.
R2.
The Transmission Owner and Generator Owner shall each provide Facility Ratings for its
solely and jointly owned Facilities that are existing Facilities, new Facilities, modifications to
existing Facilities and re-ratings of existing Facilities to its associated Reliability
Coordinator(s), Planning Authority(ies), Transmission Planner(s), and Transmission
Operator(s) as scheduled by such requesting entities.
C. Measures
M1. The Transmission Owner and Generator Owner shall each be able to demonstrate that it
developed its Facility Ratings consistent with its Facility Ratings Methodology.
M1.1
The Transmission Owner’s and Generator Owner’s Facility Ratings shall each include
ratings for its solely and jointly owned Facilities including new Facilities, existing
Facilities, modifications to existing Facilities and re-ratings of existing Facilities.
M2. The Transmission Owner and Generator Owner shall each have evidence that it provided its
Facility Ratings to its associated Reliability Coordinator(s), Planning Authority(ies),
Transmission Planner(s), and Transmission Operator(s) as scheduled by such requesting
entities.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Transmission Owner and Generator Owner shall self-certify its compliance to the
Compliance Monitor annually. The Compliance Monitor may conduct a targeted audit
once in each calendar year (January–December) and an investigation upon complaint to
assess performance.
The Performance-Reset Period shall be twelve months from the last finding of noncompliance.
Adopted by Board of Trustees: February 7, 2006
Effective Date: October 7, 2006
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
1 of 2
Standard FAC-009-1 — Establish and Communicate Facility Ratings
1.3. Data Retention
The Transmission Owner and Generator Owner shall each keep documentation for 12
months. In addition, entities found non-compliant shall keep information related to the
non-compliance until found compliant.
The Compliance Monitor shall retain audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and Generator Owner shall each make the following available
for inspection during a targeted audit by the Compliance Monitor or within 15 business
days of a request as part of an investigation upon complaint:
2.
1.4.1
Facility Ratings Methodology
1.4.2
Facility Ratings
1.4.3
Evidence that Facility Ratings were distributed
1.4.4
Distribution schedules provided by entities that requested Facility Ratings
Levels of Non-Compliance
2.1. Level 1:
Not all requested Facility Ratings associated with existing Facilities were
provided to the Reliability Coordinator(s), Planning Authority(ies), Transmission
Planner(s), and Transmission Operator(s) in accordance with their respective schedules.
2.2. Level 2:
Not all Facility Ratings associated with new Facilities, modifications to
existing Facilities, and re-ratings of existing Facilities were provided to the Reliability
Coordinator(s), Planning Authority(ies), Transmission Planner(s), and Transmission
Operator(s) in accordance with their respective schedules.
2.3. Level 3:
Facility Ratings provided were not developed consistent with the Facility
Ratings Methodology.
2.4. Level 4:
No Facility Ratings were provided to the Reliability Coordinator(s),
Planning Authority(ies), Transmission Planner(s), or Transmission Operator(s) in
accordance with their respective schedules.
E. Regional Differences
None Identified.
Version History
Version
1
Date
Action
Change Tracking
08/01/05
1.
01/20/06
2.
3.
Lower cased the word “draft” and
“drafting team” where appropriate.
Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
Changed “Timeframe” to “Time
Frame” in item D, 1.2.
Adopted by Board of Trustees: February 7, 2006
Effective Date: October 7, 2006
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
2 of 2
Standard FAC-009-1 — Establish and Communicate Facility Ratings
Appendix QC-FAC-009-1
Provisions specific to the standard FAC-009-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Establish and Communicate Facility Ratings
2.
Number:
FAC-009-1
3.
Purpose:
No specific provision
4.
Applicability:
Functions
No specific provision
Facilities
Main Transmission System (RTP)
5.
B.
No specific provision
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx, 201x
5.2.
Adoption of the appendix by the Régie de l'énergie: Month xx, 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx, 201x
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Time Fframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 2
Standard FAC-009-1 — Establish and Communicate Facility Ratings
Appendix QC-FAC-009-1
Provisions specific to the standard FAC-009-1 applicable in Québec
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Change Tracking
New
Page QC-2 of 2
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
A. Introduction
1.
Title:
System Operating Limits Methodology for the Planning Horizon
2.
Number:
FAC-010-2.1
3.
Purpose:
To ensure that System Operating Limits (SOLs) used in the reliable planning of
the Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Planning Authority
5.
Effective Date:
April 19, 2010
B. Requirements
R1.
R2.
The Planning Authority shall have a documented SOL Methodology for use in developing
SOLs within its Planning Authority Area. This SOL Methodology shall:
R1.1.
Be applicable for developing SOLs used in the planning horizon.
R1.2.
State that SOLs shall not exceed associated Facility Ratings.
R1.3.
Include a description of how to identify the subset of SOLs that qualify as IROLs.
The Planning Authority’s SOL Methodology shall include a requirement that SOLs provide
BES performance consistent with the following:
R2.1.
In the pre-contingency state and with all Facilities in service, the BES shall
demonstrate transient, dynamic and voltage stability; all Facilities shall be within their
Facility Ratings and within their thermal, voltage and stability limits. In the
determination of SOLs, the BES condition used shall reflect expected system
conditions and shall reflect changes to system topology such as Facility outages.
R2.2.
Following the single Contingencies 1 identified in Requirement 2.2.1 through
Requirement 2.2.3, the system shall demonstrate transient, dynamic and voltage
stability; all Facilities shall be operating within their Facility Ratings and within their
thermal, voltage and stability limits; and Cascading or uncontrolled separation shall
not occur.
R2.2.1. Single line to ground or three-phase Fault (whichever is more severe), with
Normal Clearing, on any Faulted generator, line, transformer, or shunt
device.
R2.2.2. Loss of any generator, line, transformer, or shunt device without a Fault.
R2.2.3. Single pole block, with Normal Clearing, in a monopolar or bipolar high
voltage direct current system.
R2.3.
Starting with all Facilities in service, the system’s response to a single Contingency,
may include any of the following:
R2.3.1. 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.
1
The Contingencies identified in R2.2.1 through R2.2.3 are the minimum contingencies that must be studied but are
not necessarily the only Contingencies that should be studied.
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 1 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
R2.3.2. System reconfiguration through manual or automatic control or protection
actions.
R2.4.
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.
R2.5.
Starting with all Facilities in service and following any of the multiple Contingencies
identified in Reliability Standard TPL-003 the system shall demonstrate transient,
dynamic and voltage stability; all Facilities shall be operating within their Facility
Ratings and within their thermal, voltage and stability limits; and Cascading or
uncontrolled separation shall not occur.
R2.6.
In determining the system’s response to any of the multiple Contingencies, identified
in Reliability Standard TPL-003, in addition to the actions identified in R2.3.1 and
R2.3.2, the following shall be acceptable:
R2.6.1. Planned or controlled interruption of electric supply to customers (load
shedding), the planned removal from service of certain generators, and/or
the curtailment of contracted Firm (non-recallable reserved) electric power
Transfers.
R3.
R4.
R5.
The Planning Authority’s methodology for determining SOLs, shall include, as a minimum, a
description of the following, along with any reliability margins applied for each:
R3.1.
Study model (must include at least the entire Planning Authority Area as well as the
critical modeling details from other Planning Authority Areas that would impact the
Facility or Facilities under study).
R3.2.
Selection of applicable Contingencies.
R3.3.
Level of detail of system models used to determine SOLs.
R3.4.
Allowed uses of Special Protection Systems or Remedial Action Plans.
R3.5.
Anticipated transmission system configuration, generation dispatch and Load level.
R3.6.
Criteria for determining when violating a SOL qualifies as an Interconnection
Reliability Operating Limit (IROL) and criteria for developing any associated IROL
Tv.
The Planning Authority shall issue its SOL Methodology, and any change to that methodology,
to all of the following prior to the effectiveness of the change:
R4.1.
Each adjacent Planning Authority and each Planning Authority that indicated it has a
reliability-related need for the methodology.
R4.2.
Each Reliability Coordinator and Transmission Operator that operates any portion of
the Planning Authority’s Planning Authority Area.
R4.3.
Each Transmission Planner that works in the Planning Authority’s Planning Authority
Area.
If a recipient of the SOL Methodology provides documented technical comments on the
methodology, the Planning Authority shall provide a documented response to that recipient
within 45 calendar days of receipt of those comments. The response shall indicate whether a
change will be made to the SOL Methodology and, if no change will be made to that SOL
Methodology, the reason why.
C. Measures
M1. The Planning Authority’s SOL Methodology shall address all of the items listed in
Requirement 1 through Requirement 3.
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 2 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
M2. The Planning Authority shall have evidence it issued its SOL Methodology and any changes to
that methodology, including the date they were issued, in accordance with Requirement 4.
M3. If the recipient of the SOL Methodology provides documented comments on its technical
review of that SOL methodology, the Planning Authority that distributed that SOL
Methodology shall have evidence that it provided a written response to that commenter within
45 calendar days of receipt of those comments in accordance with Requirement 5.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Planning Authority shall self-certify its compliance to the Compliance Monitor at
least once every three years. New Planning Authorities shall demonstrate compliance
through an on-site audit conducted by the Compliance Monitor within the first year that it
commences operation. The Compliance Monitor shall also conduct an on-site audit once
every nine years and an investigation upon complaint to assess performance.
The Performance-Reset Period shall be twelve months from the last non-compliance.
1.3. Data Retention
The Planning Authority shall keep all superseded portions to its SOL Methodology for 12
months beyond the date of the change in that methodology and shall keep all documented
comments on its SOL Methodology and associated responses for three years. In addition,
entities found non-compliant shall keep information related to the non-compliance until
found compliant.
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Planning Authority shall make the following available for inspection during an onsite audit by the Compliance Monitor or within 15 business days of a request as part of an
investigation upon complaint:
2.
1.4.1
SOL Methodology.
1.4.2
Documented comments provided by a recipient of the SOL Methodology on its
technical review of a SOL Methodology, and the associated responses.
1.4.3
Superseded portions of its SOL Methodology that had been made within the past
12 months.
1.4.4
Evidence that the SOL Methodology and any changes to the methodology that
occurred within the past 12 months were issued to all required entities.
Levels of Non-Compliance for Western Interconnection: (To be replaced with VSLs once
developed and approved by WECC)
2.1. Level 1:
There shall be a level one non-compliance if either of the following
conditions exists:
2.1.1
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded.
2.1.2
No evidence of responses to a recipient’s comments on the SOL Methodology.
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 3 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
2.2. Level 2:
The SOL Methodology did not include a requirement to address all of the
elements in R2.1 through R2.3 and E1.
2.3. Level 3:
There shall be a level three non-compliance if any of the following
conditions exists:
2.3.1
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded and the methodology did not include evaluation of
system response to one of the three types of single Contingencies identified in
R2.2.
2.3.2
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded and the methodology did not include evaluation of
system response to two of the seven types of multiple Contingencies identified in
E1.1.
2.3.3
The System Operating Limits Methodology did not include a statement
indicating that Facility Ratings shall not be exceeded and the methodology did
not address two of the six required topics in R3.
2.4. Level 4:
with R4
The SOL Methodology was not issued to all required entities in accordance
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 4 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
3.
Violation Severity Levels:
Requirement
Lower
Moderate
High
Severe
R1
Not applicable.
The Planning Authority has a
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area, but it does not address
R1.2
The Planning Authority has a
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area, but it does not address
R1.3.
The Planning Authority has a
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area, but it does not address
R1.1.
OR
The Planning Authority has no
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area.
R2
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance following single and
multiple contingencies, but does
not address the pre-contingency
state (R2.1)
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance in the precontingency state and following
single contingencies, but does
not address multiple
contingencies. (R2.5-R2.6)
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance in the precontingency state and following
multiple contingencies, but does
not meet the performance for
response to single
contingencies. (R2.2 –R2.4)
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance in the precontingency state but does not
require that SOLs be set to meet
the BES performance specified
for response to single
contingencies (R2.2-R2.4) and
does not require that SOLs be
set to meet the BES
performance specified for
response to multiple
contingencies. (R2.5-R2.6)
R3
The Planning Authority has a
methodology for determining
SOLs that includes a description
for all but one of the following:
R3.1 through R3.6.
The Planning Authority has a
methodology for determining
SOLs that includes a description
for all but two of the following:
R3.1 through R3.6.
The Planning Authority has a
methodology for determining
SOLs that includes a description
for all but three of the following:
R3.1 through R3.6.
The Planning Authority has a
methodology for determining
SOLs that is missing a
description of four or more of the
following: R3.1 through R3.6.
R4
One or both of the following:
The Planning Authority issued its
SOL Methodology and changes
One of the following:
The Planning Authority issued its
SOL Methodology and changes
One of the following:
The Planning Authority issued its
SOL Methodology and changes
One of the following:
The Planning Authority failed to
issue its SOL Methodology and
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 5 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
Requirement
Lower
Moderate
High
Severe
to that methodology to all but
one of the required entities.
For a change in methodology,
the changed methodology was
provided up to 30 calendar days
after the effectiveness of the
change.
to that methodology to all but
one of the required entities AND
for a change in methodology, the
changed methodology was
provided 30 calendar days or
more, but less than 60 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
two of the required entities AND
for a change in methodology, the
changed methodology was
provided up to 30 calendar days
after the effectiveness of the
change.
to that methodology to all but
one of the required entities AND
for a change in methodology, the
changed methodology was
provided 60 calendar days or
more, but less than 90 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
two of the required entities AND
for a change in methodology, the
changed methodology was
provided 30 calendar days or
more, but less than 60 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
three of the required entities
AND for a change in
methodology, the changed
methodology was provided up to
30 calendar days after the
effectiveness of the change.
changes to that methodology to
more than three of the required
entities.
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
one of the required entities AND
for a change in methodology, the
changed methodology was
provided 90 calendar days or
more after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
two of the required entities AND
for a change in methodology, the
changed methodology was
provided 60 calendar days or
more, but less than 90 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
three of the required entities
AND for a change in
methodology, the changed
methodology was provided 30
calendar days or more, but less
than 60 calendar days after the
effectiveness of the change.
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 6 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
Requirement
Lower
Moderate
High
Severe
four of the required entities AND
for a change in methodology, the
changed methodology was
provided up to 30 calendar days
after the effectiveness of the
change.
R5
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was longer
than 45 calendar days but less
than 60 calendar days.
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was 60
calendar days or longer but less
than 75 calendar days.
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was 75
calendar days or longer but less
than 90 calendar days.
OR
The Planning Authority’s
response to documented
technical comments on its SOL
Methodology indicated that a
change will not be made, but did
not include an explanation of
why the change will not be
made.
Page 7 of 9
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was 90
calendar days or longer.
OR
The Planning Authority’s
response to documented
technical comments on its SOL
Methodology did not indicate
whether a change will be made
to the SOL Methodology.
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
E. Regional Differences
1.
The following Interconnection-wide Regional Difference shall be applicable in the Western
Interconnection:
1.1. As governed by the requirements of R2.5 and R2.6, starting with all Facilities in service,
shall require the evaluation of the following multiple Facility Contingencies when
establishing SOLs:
1.1.1
Simultaneous permanent phase to ground Faults on different phases of each of
two adjacent transmission circuits on a multiple circuit tower, with Normal
Clearing. If multiple circuit towers are used only for station entrance and exit
purposes, and if they do not exceed five towers at each station, then this
condition is an acceptable risk and therefore can be excluded.
1.1.2
A permanent phase to ground Fault on any generator, transmission circuit,
transformer, or bus section with Delayed Fault Clearing except for bus
sectionalizing breakers or bus-tie breakers addressed in E1.1.7
1.1.3
Simultaneous permanent loss of both poles of a direct current bipolar Facility
without an alternating current Fault.
1.1.4
The failure of a circuit breaker associated with a Special Protection System to
operate when required following: the loss of any element without a Fault; or a
permanent phase to ground Fault, with Normal Clearing, on any transmission
circuit, transformer or bus section.
1.1.5
A non-three phase Fault with Normal Clearing on common mode Contingency of
two adjacent circuits on separate towers unless the event frequency is determined
to be less than one in thirty years.
1.1.6
A common mode outage of two generating units connected to the same
switchyard, not otherwise addressed by FAC-010.
1.1.7
The loss of multiple bus sections as a result of failure or delayed clearing of a bus
tie or bus sectionalizing breaker to clear a permanent Phase to Ground Fault.
1.2. SOLs shall be established such that for multiple Facility Contingencies in E1.1.1 through
E1.1.5 operation within the SOL shall provide system performance consistent with the
following:
1.2.1
All Facilities are operating within their applicable Post-Contingency thermal,
frequency and voltage limits.
1.2.2
Cascading does not occur.
1.2.3
Uncontrolled separation of the system does not occur.
1.2.4
The system demonstrates transient, dynamic and voltage stability.
1.2.5
Depending on system design and expected system impacts, the controlled
interruption of electric supply to customers (load shedding), the planned removal
from service of certain generators, and/or the curtailment of contracted firm (nonrecallable reserved) electric power transfers may be necessary to maintain the
overall security of the interconnected transmission systems.
1.2.6
Interruption of firm transfer, Load or system reconfiguration is permitted through
manual or automatic control or protection actions.
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 8 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
1.2.7
To prepare for the next Contingency, system adjustments are permitted, including
changes to generation, Load and the transmission system topology when
determining limits.
1.3. SOLs shall be established such that for multiple Facility Contingencies in E1.1.6 through
E1.1.7 operation within the SOL shall provide system performance consistent with the
following with respect to impacts on other systems:
1.3.1
Cascading does not occur.
1.4. The Western Interconnection may make changes (performance category adjustments) to
the Contingencies required to be studied and/or the required responses to Contingencies
for specific facilities based on actual system performance and robust design. Such
changes will apply in determining SOLs.
Version History
Version
Date
Action
Change Tracking
1
November 1,
2006
Adopted by Board of Trustees
New
1
November 1,
2006
Fixed typo. Removed the word “each” from
the 1st sentence of section D.1.3, Data
Retention.
01/11/07
2
June 24, 2008
Adopted by Board of Trustees; FERC Order
705
Revised
Changed the effective date to July 1, 2008
Changed “Cascading Outage” to
“Cascading”
Replaced Levels of Non-compliance with
Violation Severity Levels
Revised
January 22,
2010
Updated effective date and footer to April
29, 2009 based on the March 20, 2009
FERC Order
Update
2.1
November 5,
2009
Adopted by the Board of Trustees — errata
change Section E1.1 modified to reflect the
renumbering of requirements R2.4 and R2.5
from FAC-010-1 to R2.5 and R2.6 in FAC010-2.
Errata
2.1
April 19, 2010
FERC Approved — errata change Section
E1.1 modified to reflect the renumbering of
requirements R2.4 and R2.5 from FAC-0101 to R2.5 and R2.6 in FAC-010-2.
Errata
2
2
Adopted by the Régie de l'énergie (Decision D-201x-xxx): Month xx, 201x
Page 9 of 9
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
Appendix QC-FAC-010-2.1
Provisions specific to the standard FAC-010-2.1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
System Operating Limits Methodology for the Planning Horizon
2.
Number:
FAC-010-2.1
3.
Purpose:
No specific provision
4.
Applicability:
Functions
No specific provision
Facilities
Main Transmission System (RTP)
5.
B.
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx, 201x
5.2.
Adoption of the appendix by the Régie de l'énergie: Month xx, 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Time Fframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance for Western Interconnection
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 2
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
Appendix QC-FAC-010-2.1
Provisions specific to the standard FAC-010-2.1 applicable in Québec
3.
Violation Severity Levels
No specific provision
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Change Tracking
New
Page QC-2 of 2
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
A. Introduction
1.
Title:
System Operating Limits Methodology for the Operations Horizon
2.
Number:
FAC-011-2
3.
Purpose:
To ensure that System Operating Limits (SOLs) used in the reliable operation of
the Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Reliability Coordinator
5.
Effective Date:
April 29, 2009
B. Requirements
R1. The Reliability Coordinator shall have a documented methodology for use in developing SOLs
(SOL Methodology) within its Reliability Coordinator Area. This SOL Methodology shall:
R2.
R1.1.
Be applicable for developing SOLs used in the operations horizon.
R1.2.
State that SOLs shall not exceed associated Facility Ratings.
R1.3.
Include a description of how to identify the subset of SOLs that qualify as IROLs.
The Reliability Coordinator’s SOL Methodology shall include a requirement that SOLs
provide BES performance consistent with the following:
R2.1.
In the pre-contingency state, the BES shall demonstrate transient, dynamic and
voltage stability; all Facilities shall be within their Facility Ratings and within their
thermal, voltage and stability limits. In the determination of SOLs, the BES condition
used shall reflect current or expected system conditions and shall reflect changes to
system topology such as Facility outages.
R2.2.
Following the single Contingencies1 identified in Requirement 2.2.1 through
Requirement 2.2.3, the system shall demonstrate transient, dynamic and voltage
stability; all Facilities shall be operating within their Facility Ratings and within their
thermal, voltage and stability limits; and Cascading or uncontrolled separation shall
not occur.
R2.2.1. Single line to ground or 3-phase Fault (whichever is more severe), with
Normal Clearing, on any Faulted generator, line, transformer, or shunt
device.
R2.2.2. Loss of any generator, line, transformer, or shunt device without a Fault.
R2.2.3. Single pole block, with Normal Clearing, in a monopolar or bipolar high
voltage direct current system.
R2.3.
In determining the system’s response to a single Contingency, the following shall be
acceptable:
R2.3.1. 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.
1
The Contingencies identified in FAC-011 R2.2.1 through R2.2.3 are the minimum contingencies that must be
studied but are not necessarily the only Contingencies that should be studied.
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 1 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
R2.3.2. Interruption of other network customers, (a) only if the system has already
been adjusted, or is being adjusted, following at least one prior outage, or
(b) if the real-time operating conditions are more adverse than anticipated in
the corresponding studies
R2.3.3. System reconfiguration through manual or automatic control or protection
actions.
R2.4.
R3.
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.
The Reliability Coordinator’s methodology for determining SOLs, shall include, as a
minimum, a description of the following, along with any reliability margins applied for each:
R3.1.
Study model (must include at least the entire Reliability Coordinator Area as well as
the critical modeling details from other Reliability Coordinator Areas that would
impact the Facility or Facilities under study.)
R3.2.
Selection of applicable Contingencies
R3.3.
A process for determining which of the stability limits associated with the list of
multiple contingencies (provided by the Planning Authority in accordance with FAC014 Requirement 6) are applicable for use in the operating horizon given the actual or
expected system conditions.
R3.3.1. This process shall address the need to modify these limits, to modify the list
of limits, and to modify the list of associated multiple contingencies.
R4.
R5.
R3.4.
Level of detail of system models used to determine SOLs.
R3.5.
Allowed uses of Special Protection Systems or Remedial Action Plans.
R3.6.
Anticipated transmission system configuration, generation dispatch and Load level
R3.7.
Criteria for determining when violating a SOL qualifies as an Interconnection
Reliability Operating Limit (IROL) and criteria for developing any associated IROL
Tv .
The Reliability Coordinator shall issue its SOL Methodology and any changes to that
methodology, prior to the effectiveness of the Methodology or of a change to the Methodology,
to all of the following:
R4.1.
Each adjacent Reliability Coordinator and each Reliability Coordinator that indicated
it has a reliability-related need for the methodology.
R4.2.
Each Planning Authority and Transmission Planner that models any portion of the
Reliability Coordinator’s Reliability Coordinator Area.
R4.3.
Each Transmission Operator that operates in the Reliability Coordinator Area.
If a recipient of the SOL Methodology provides documented technical comments on the
methodology, the Reliability Coordinator shall provide a documented response to that recipient
within 45 calendar days of receipt of those comments. The response shall indicate whether a
change will be made to the SOL Methodology and, if no change will be made to that SOL
Methodology, the reason why.
C. Measures
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 2 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
M1. The Reliability Coordinator’s SOL Methodology shall address all of the items listed in
Requirement 1 through Requirement 3.
M2. The Reliability Coordinator shall have evidence it issued its SOL Methodology, and any
changes to that methodology, including the date they were issued, in accordance with
Requirement 4.
M3. If the recipient of the SOL Methodology provides documented comments on its technical
review of that SOL methodology, the Reliability Coordinator that distributed that SOL
Methodology shall have evidence that it provided a written response to that commenter within
45 calendar days of receipt of those comments in accordance with Requirement 5
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Reliability Coordinator shall self-certify its compliance to the Compliance Monitor
at least once every three years. New Reliability Authorities shall demonstrate
compliance through an on-site audit conducted by the Compliance Monitor within the
first year that it commences operation. The Compliance Monitor shall also conduct an onsite audit once every nine years and an investigation upon complaint to assess
performance.
The Performance-Reset Period shall be twelve months from the last non-compliance.
1.3. Data Retention
The Reliability Coordinator shall keep all superseded portions to its SOL Methodology
for 12 months beyond the date of the change in that methodology and shall keep all
documented comments on its SOL Methodology and associated responses for three years.
In addition, entities found non-compliant shall keep information related to the noncompliance until found compliant.
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Reliability Coordinator shall make the following available for inspection during an
on-site audit by the Compliance Monitor or within 15 business days of a request as part
of an investigation upon complaint:
2.
1.4.1
SOL Methodology.
1.4.2
Documented comments provided by a recipient of the SOL Methodology on its
technical review of a SOL Methodology, and the associated responses.
1.4.3
Superseded portions of its SOL Methodology that had been made within the past
12 months.
1.4.4
Evidence that the SOL Methodology and any changes to the methodology that
occurred within the past 12 months were issued to all required entities.
Levels of Non-Compliance for Western Interconnection: (To be replaced with VSLs once
developed and approved by WECC)
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 3 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
2.1. Level 1:
There shall be a level one non-compliance if either of the following
conditions exists:
2.1.1
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded.
2.1.2
No evidence of responses to a recipient’s comments on the SOL Methodology
2.2. Level 2:
The SOL Methodology did not include a requirement to address all of the
elements in R3.1, R3.2, R3.4 through R3.7 and E1.
2.3. Level 3:
There shall be a level three non-compliance if any of the following
conditions exists:
2.3.1
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded and the methodology did not include evaluation of
system response to one of the three types of single Contingencies identified in
R2.2.
2.3.2
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded and the methodology did not include evaluation of
system response to two of the seven types of multiple Contingencies identified in
E1.1.
2.3.3
The System Operating Limits Methodology did not include a statement
indicating that Facility Ratings shall not be exceeded and the methodology did
not address two of the six required topics in R3.1, R3.2, R3.4 through R3.7.
2.4. Level 4:
with R4.
The SOL Methodology was not issued to all required entities in accordance
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 4 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
3.
Violation Severity Levels:
Requirement
Lower
Moderate
High
Severe
R1
Not applicable.
The Reliability Coordinator has a
documented SOL Methodology
for use in developing SOLs
within its Reliability Coordinator
Area, but it does not address
R1.2
The Reliability Coordinator has a
documented SOL Methodology
for use in developing SOLs
within its Reliability Coordinator
Area, but it does not address
R1.3.
The Reliability Coordinator has a
documented SOL Methodology
for use in developing SOLs
within its Reliability Coordinator
Area, but it does not address
R1.1.
OR
The Reliability Coordinator has
no documented SOL
Methodology for use in
developing SOLs within its
Reliability Coordinator Area.
R2
The Reliability Coordinator‘s
SOL Methodology requires that
SOLs are set to meet BES
performance following single
contingencies, but does not
require that SOLs are set to
meet BES performance in the
pre-contingency state. (R2.1)
Not applicable.
The Reliability Coordinator‘s
SOL Methodology requires that
SOLs are set to meet BES
performance in the precontingency state, but does not
require that SOLs are set to
meet BES performance following
single contingencies. (R2.2 –
R2.4)
The Reliability Coordinator’s
SOL Methodology does not
require that SOLs are set to
meet BES performance in the
pre-contingency state and does
not require that SOLs are set to
meet BES performance following
single contingencies. (R2.1
through R2.4)
R3
The Reliability Coordinator has a
methodology for determining
SOLs that includes a description
for all but one of the following:
R3.1 through R3.7.
The Reliability Coordinator has a
methodology for determining
SOLs that includes a description
for all but two of the following:
R3.1 through R3.7.
The Reliability Coordinator has a
methodology for determining
SOLs that includes a description
for all but three of the following:
R3.1 through R3.7.
The Reliability Coordinator has a
methodology for determining
SOLs that is missing a
description of three or more of
the following: R3.1 through R3.7.
R4
One or both of the following:
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but one of the required
entities.
For a change in methodology,
the changed methodology was
One of the following:
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but one of the required
entities AND for a change in
methodology, the changed
methodology was provided 30
One of the following:
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but one of the required
entities AND for a change in
methodology, the changed
methodology was provided 60
One of the following:
The Reliability Coordinator failed
to issue its SOL Methodology
and changes to that
methodology to more than three
of the required entities.
The Reliability Coordinator
issued its SOL Methodology and
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 5 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
Requirement
Lower
provided up to 30 calendar days
after the effectiveness of the
change.
Moderate
calendar days or more, but less
than 60 calendar days after the
effectiveness of the change.
OR
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but two of the required entities
AND for a change in
methodology, the changed
methodology was provided up to
30 calendar days after the
effectiveness of the change.
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
High
calendar days or more, but less
than 90 calendar days after the
effectiveness of the change.
OR
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but two of the required entities
AND for a change in
methodology, the changed
methodology was provided 30
calendar days or more, but less
than 60 calendar days after the
effectiveness of the change.
OR
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but three of the required
entities AND for a change in
methodology, the changed
methodology was provided up to
30 calendar days after the
effectiveness of the change.
Severe
changes to that methodology to
all but one of the required
entities AND for a change in
methodology, the changed
methodology was provided 90
calendar days or more after the
effectiveness of the change.
OR
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but two of the required entities
AND for a change in
methodology, the changed
methodology was provided 60
calendar days or more, but less
than 90 calendar days after the
effectiveness of the change.
OR
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but three of the required
entities AND for a change in
methodology, the changed
methodology was provided 30
calendar days or more, but less
than 60 calendar days after the
effectiveness of the change.
OR
The Reliability Coordinator
issued its SOL Methodology and
changes to that methodology to
all but four of the required
entities AND for a change in
methodology, the changed
methodology was provided up to
Page 6 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
Requirement
R5
Lower
The Reliability Coordinator
received documented technical
comments on its SOL
Methodology and provided a
complete response in a time
period that was longer than 45
calendar days but less than 60
calendar days.
Moderate
High
The Reliability Coordinator
received documented technical
comments on its SOL
Methodology and provided a
complete response in a time
period that was 60 calendar days
or longer but less than 75
calendar days.
The Reliability Coordinator
received documented technical
comments on its SOL
Methodology and provided a
complete response in a time
period that was 75 calendar days
or longer but less than 90
calendar days.
OR
The Reliability Coordinator’s
response to documented
technical comments on its SOL
Methodology indicated that a
change will not be made, but did
not include an explanation of
why the change will not be
made.
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Severe
30 calendar days after the
effectiveness of the change.
The Reliability Coordinator
received documented technical
comments on its SOL
Methodology and provided a
complete response in a time
period that was 90 calendar days
or longer.
OR
The Reliability Coordinator’s
response to documented
technical comments on its SOL
Methodology did not indicate
whether a change will be made
to the SOL Methodology.
Page 7 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
Regional Differences
1.
The following Interconnection-wide Regional Difference shall be applicable in the Western
Interconnection:
1.1. As governed by the requirements of R3.3, starting with all Facilities in service, shall
require the evaluation of the following multiple Facility Contingencies when establishing
SOLs:
1.1.1
Simultaneous permanent phase to ground Faults on different phases of each of
two adjacent transmission circuits on a multiple circuit tower, with Normal
Clearing. If multiple circuit towers are used only for station entrance and exit
purposes, and if they do not exceed five towers at each station, then this
condition is an acceptable risk and therefore can be excluded.
1.1.2
A permanent phase to ground Fault on any generator, transmission circuit,
transformer, or bus section with Delayed Fault Clearing except for bus
sectionalizing breakers or bus-tie breakers addressed in E1.1.7
1.1.3
Simultaneous permanent loss of both poles of a direct current bipolar Facility
without an alternating current Fault.
1.1.4
The failure of a circuit breaker associated with a Special Protection System to
operate when required following: the loss of any element without a Fault; or a
permanent phase to ground Fault, with Normal Clearing, on any transmission
circuit, transformer or bus section.
1.1.5
A non-three phase Fault with Normal Clearing on common mode Contingency of
two adjacent circuits on separate towers unless the event frequency is determined
to be less than one in thirty years.
1.1.6
A common mode outage of two generating units connected to the same
switchyard, not otherwise addressed by FAC-011.
1.1.7
The loss of multiple bus sections as a result of failure or delayed clearing of a bus
tie or bus sectionalizing breaker to clear a permanent Phase to Ground Fault.
1.2. SOLs shall be established such that for multiple Facility Contingencies in E1.1.1 through
E1.1.5 operation within the SOL shall provide system performance consistent with the
following:
1.2.1
All Facilities are operating within their applicable Post-Contingency thermal,
frequency and voltage limits.
1.2.2
Cascading does not occur.
1.2.3
Uncontrolled separation of the system does not occur.
1.2.4
The system demonstrates transient, dynamic and voltage stability.
1.2.5
Depending on system design and expected system impacts, the controlled
interruption of electric supply to customers (load shedding), the planned removal
from service of certain generators, and/or the curtailment of contracted firm (nonrecallable reserved) electric power transfers may be necessary to maintain the
overall security of the interconnected transmission systems.
1.2.6
Interruption of firm transfer, Load or system reconfiguration is permitted through
manual or automatic control or protection actions.
Adopted by Board of Trustees: June 24, 2008
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 8 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
1.2.7
To prepare for the next Contingency, system adjustments are permitted, including
changes to generation, Load and the transmission system topology when
determining limits.
1.3. SOLs shall be established such that for multiple Facility Contingencies in E1.1.6 through
E1.1.7 operation within the SOL shall provide system performance consistent with the
following with respect to impacts on other systems:
1.3.1
Cascading does not occur.
1.4. The Western Interconnection may make changes (performance category adjustments) to
the Contingencies required to be studied and/or the required responses to Contingencies
for specific facilities based on actual system performance and robust design. Such
changes will apply in determining SOLs.
Version History
Version
1
Date
Action
Change Tracking
November 1,
2006
Adopted by Board of Trustees
New
Changed the effective date to October 1,
2008
Changed “Cascading Outage” to
“Cascading”
Replaced Levels of Non-compliance with
Violation Severity Levels
Corrected footnote 1 to reference FAC-011
rather than FAC-010
Revised
2
2
June 24, 2008
Adopted by Board of Trustees: FERC Order
705
Revised
2
January 22,
2010
Updated effective date and footer to April
29, 2009 based on the March 20, 2009
FERC Order
Update
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by Régie de l'énergie (Decision 201x-xxx): Month xx, 201x
Page 9 of 9
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
Appendix QC-FAC-011-2
Provisions specific to the standard FAC-011-2 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
System Operating Limits Methodology for the Operations Horizon
2.
Number:
FAC-011-2
3.
Purpose:
No specific provision
4.
Applicability:
Functions
No specific provision
Facilities
Main Transmission System (RTP)
5.
No specific provision
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx 201x
5.2.
Adoption of the appendix by the Régie de l'énergie: Month xx 201x
4.3.Effective date of the standard and its appendix in Québec: Month xx 201x
5.3.
B.
Scope: Main Transmission System (MTS)
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Time Fframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 3
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
Appendix QC-FAC-011-2
Provisions specific to the standard FAC-011-2 applicable in Québec
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-2 of 3
Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
Appendix QC-FAC-011-2
Provisions specific to the standard FAC-011-2 applicable in Québec
3.
Violation Severity Levels
All occurrences of the term “BES” are replaced by “Main Transmission SystemRTP”.
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Change Tracking
New
Page QC-3 of 3
Standard FAC-013-1 — Establish and Communicate Transfer Capabilities
A. Introduction
1.
Title:
Establish and Communicate Transfer Capabilities
2.
Number:
FAC-013-1
3.
Purpose:
To ensure that Transfer Capabilities used in the reliable planning and operation
of the Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Reliability Coordinator required by its Regional Reliability Organization to establish
inter-regional and intra-regional Transfer Capabilities
4.2. Planning Authority required by its Regional Reliability Organization to establish interregional and intra-regional Transfer Capabilities
5.
Effective Date:
October 7, 2006
B. Requirements
R1.
The Reliability Coordinator and Planning Authority shall each establish a set of inter-regional
and intra-regional Transfer Capabilities that is consistent with its current Transfer Capability
Methodology.
R2.
The Reliability Coordinator and Planning Authority shall each provide its inter-regional and
intra-regional Transfer Capabilities to those entities that have a reliability-related need for such
Transfer Capabilities and make a written request that includes a schedule for delivery of such
Transfer Capabilities as follows:
R2.1.
The Reliability Coordinator shall provide its Transfer Capabilities to its associated
Regional Reliability Organization(s), to its adjacent Reliability Coordinators, and to
the Transmission Operators, Transmission Service Providers and Planning Authorities
that work in its Reliability Coordinator Area.
R2.2.
The Planning Authority shall provide its Transfer Capabilities to its associated
Reliability Coordinator(s) and Regional Reliability Organization(s), and to the
Transmission Planners and Transmission Service Provider(s) that work in its Planning
Authority Area.
C. Measures
M1. The Reliability Coordinator and Planning Authority shall each be able to demonstrate that it
developed its Transfer Capabilities consistent with its Transfer Capability Methodology.
M2. The Reliability Coordinator and Planning Authority shall each have evidence that it provided
its Transfer Capabilities in accordance with schedules supplied by the requestors of such
Transfer Capabilities.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Timeframe
The Reliability Coordinator and Planning Authority shall each verify compliance through
self-certification submitted to the Compliance Monitor annually. The Compliance
Adopted by Board of Trustees: February 7, 2006
Effective Date: October 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
1 of 2
Standard FAC-013-1 — Establish and Communicate Transfer Capabilities
Monitor may conduct a targeted audit once in each calendar year (January–December)
and an investigation upon a complaint to assess compliance.
The Performance-Reset Period shall be twelve months from the last finding of noncompliance.
1.3. Data Retention
The Planning Authority and Reliability Coordinator shall each keep documentation for 12
months. In addition, entities found non-compliant shall keep information related to the
non-compliance until found compliant.
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Planning Authority and Reliability Coordinator shall each make the following
available for inspection during a targeted audit by the Compliance Monitor or within 15
business days of a request as part of an investigation upon complaint:
2.
1.4.1
Transfer Capability Methodology.
1.4.2
Inter-regional and Intra-regional Transfer Capabilities.
1.4.3
Evidence that Transfer Capabilities were distributed.
1.4.4
Distribution schedules provided by entities that requested Transfer Capabilities.
Levels of Non-Compliance
2.1. Level 1:
Not applicable.
2.2. Level 2:
Not all requested Transfer Capabilities were provided in accordance with
their respective schedules.
2.3. Level 3:
Transfer Capabilities were not developed consistent with the Transfer
Capability Methodology.
2.4. Level 4:
No requested Transfer Capabilities were provided in accordance with their
respective schedules.
E. Regional Differences
None identified.
Version History
Version
1
Date
Action
Change Tracking
08/01/05
1. Changed incorrect use of certain
hyphens (-) to “en dash (–).”
2. Lower cased the word “draft” and
“drafting team” where appropriate.
3. Changed Anticipated Action #5,
page 1, from “30-day” to “Thirtyday.”
4. Added or removed “periods.”
01/20/05
Adopted by Board of Trustees: February 7, 2006
Effective Date: October 7, 2006
Adopted by the Régie de l'énergie (Décision D-2012-091): July 25, 2012
2 of 2
Standard FAC-013-1 — Establish and Communicate Transfer Capabilities
Appendix QC-FAC-013-1
Provisions specific to the standard FAC-013-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.This appendix
establishes specific provisions for the application of the standard in Québec and is an integral part of the
standard. Provisions of the standard and of its appendix must be read jointly for comprehension and
interpretation purposes. If there should happen to be an interpretation question between the standard and
its appendix, the present appendix shall take precedence over the standard provisions.
A.
B.
Introduction
1.
Title:
Establish and Communicate Transfer Capabilities
2.
Number:
FAC-013-1
3.
Purpose:
No specific provision
4.
Applicability:
No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx 201xJuly 25, 2012
5.2.
Adoption of the appendix by the Régie de l'énergie: July 25, 2012Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
E.
Regional Differences
No specific provision
Adopted by the Régie de l’énergie (Décision D-2012x-xxxx091): July 25, 2012Month xx, 201x
Page QC-1 of 2
Standard FAC-013-1 — Establish and Communicate Transfer Capabilities
Appendix QC-FAC-013-1
Provisions specific to the standard FAC-013-1 applicable in Québec
F.Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Month xx, 201x
Effective date
Change Tracking
Adopted by the Régie de l’énergie (Décision D-2012x-xxxx091): July 25, 2012Month xx, 201x
New
Page QC-2 of 2
Standard FAC-014-2 — Establish and Communicate System Operating Limits
A. Introduction
1.
Title:
Establish and Communicate System Operating Limits
2.
Number:
FAC-014-2
3.
Purpose:
To ensure that System Operating Limits (SOLs) used in the reliable planning and
operation of the Bulk Electric System (BES) are determined based on an established
methodology or methodologies.
4.
Applicability
4.1. Reliability Coordinator
4.2. Planning Authority
4.3. Transmission Planner
4.4. Transmission Operator
5.
Effective Date:
April 29, 2009
B. Requirements
R1.
The Reliability Coordinator shall ensure that SOLs, including Interconnection Reliability
Operating Limits (IROLs), for its Reliability Coordinator Area are established and that the
SOLs (including Interconnection Reliability Operating Limits) are consistent with its SOL
Methodology.
R2.
The Transmission Operator shall establish SOLs (as directed by its Reliability Coordinator) for
its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.
R3.
The Planning Authority shall establish SOLs, including IROLs, for its Planning Authority Area
that are consistent with its SOL Methodology.
R4.
The Transmission Planner shall establish SOLs, including IROLs, for its Transmission
Planning Area that are consistent with its Planning Authority’s SOL Methodology.
R5.
The Reliability Coordinator, Planning Authority and Transmission Planner shall each provide
its SOLs and IROLs to those entities that have a reliability-related need for those limits and
provide a written request that includes a schedule for delivery of those limits as follows:
R5.1.
The Reliability Coordinator shall provide its SOLs (including the subset of SOLs that
are IROLs) to adjacent Reliability Coordinators and Reliability Coordinators who
indicate a reliability-related need for those limits, and to the Transmission Operators,
Transmission Planners, Transmission Service Providers and Planning Authorities
within its Reliability Coordinator Area. For each IROL, the Reliability Coordinator
shall provide the following supporting information:
R5.1.1. Identification and status of the associated Facility (or group of Facilities)
that is (are) critical to the derivation of the IROL.
R5.1.2. The value of the IROL and its associated Tv.
R5.1.3. The associated Contingency(ies).
R5.1.4. The type of limitation represented by the IROL (e.g., voltage collapse,
angular stability).
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 1 of 6
Standard FAC-014-2 — Establish and Communicate System Operating Limits
R6.
R5.2.
The Transmission Operator shall provide any SOLs it developed to its Reliability
Coordinator and to the Transmission Service Providers that share its portion of the
Reliability Coordinator Area.
R5.3.
The Planning Authority shall provide its SOLs (including the subset of SOLs that are
IROLs) to adjacent Planning Authorities, and to Transmission Planners, Transmission
Service Providers, Transmission Operators and Reliability Coordinators that work
within its Planning Authority Area.
R5.4.
The Transmission Planner shall provide its SOLs (including the subset of SOLs that
are IROLs) to its Planning Authority, Reliability Coordinators, Transmission
Operators, and Transmission Service Providers that work within its Transmission
Planning Area and to adjacent Transmission Planners.
The Planning Authority shall identify the subset of multiple contingencies (if any), from
Reliability Standard TPL-003 which result in stability limits.
R6.1.
The Planning Authority shall provide this list of multiple contingencies and the
associated stability limits to the Reliability Coordinators that monitor the facilities
associated with these contingencies and limits.
R6.2.
If the Planning Authority does not identify any stability-related multiple
contingencies, the Planning Authority shall so notify the Reliability Coordinator.
C. Measures
M1. The Reliability Coordinator, Planning Authority, Transmission Operator, and Transmission
Planner shall each be able to demonstrate that it developed its SOLs (including the subset of
SOLs that are IROLs) consistent with the applicable SOL Methodology in accordance with
Requirements 1 through 4.
M2. The Reliability Coordinator, Planning Authority, Transmission Operator, and Transmission
Planner shall each have evidence that its SOLs (including the subset of SOLs that are IROLs)
were supplied in accordance with schedules supplied by the requestors of such SOLs as
specified in Requirement 5.
M3. The Planning Authority shall have evidence it identified a list of multiple contingencies (if any)
and their associated stability limits and provided the list and the limits to its Reliability
Coordinators in accordance with Requirement 6.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
The Reliability Coordinator, Planning Authority, Transmission Operator, and
Transmission Planner shall each verify compliance through self-certification submitted to
its Compliance Monitor annually. The Compliance Monitor may conduct a targeted audit
once in each calendar year (January – December) and an investigation upon a complaint
to assess performance.
The Performance-Reset Period shall be twelve months from the last finding of noncompliance.
1.3. Data Retention
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 2 of 6
Standard FAC-014-2 — Establish and Communicate System Operating Limits
The Reliability Coordinator, Planning Authority, Transmission Operator, and
Transmission Planner shall each keep documentation for 12 months. In addition, entities
found non-compliant shall keep information related to non-compliance until found
compliant.
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Reliability Coordinator, Planning Authority, Transmission Operator, and
Transmission Planner shall each make the following available for inspection during a
targeted audit by the Compliance Monitor or within 15 business days of a request as part
of an investigation upon complaint:
1.4.1
SOL Methodology(ies)
1.4.2
SOLs, including the subset of SOLs that are IROLs and the IROLs supporting
information
1.4.3
Evidence that SOLs were distributed
1.4.4
Evidence that a list of stability-related multiple contingencies and their associated
limits were distributed
1.4.5
Distribution schedules provided by entities that requested SOLs
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 3 of 6
Standard FAC-014-2 — Establish and Communicate System Operating Limits
2.
Requirement
Violation Severity Levels:
Lower
Moderate
High
Severe
R1
There are SOLs, for the
Reliability Coordinator Area, but
from 1% up to but less than 25%
of these SOLs are inconsistent
with the Reliability Coordinator’s
SOL Methodology. (R1)
There are SOLs, for the
Reliability Coordinator Area, but
25% or more, but less than 50%
of these SOLs are inconsistent
with the Reliability Coordinator’s
SOL Methodology. (R1)
There are SOLs, for the
Reliability Coordinator Area, but
50% or more, but less than 75%
of these SOLs are inconsistent
with the Reliability Coordinator’s
SOL Methodology. (R1)
There are SOLs for the Reliability
Coordinator Area, but 75% or
more of these SOLs are
inconsistent with the Reliability
Coordinator’s SOL Methodology.
(R1)
R2
The Transmission Operator has
established SOLs for its portion
of the Reliability Coordinator
Area, but from 1% up to but less
than 25% of these SOLs are
inconsistent with the Reliability
Coordinator’s SOL Methodology.
(R2)
The Transmission Operator has
established SOLs for its portion
of the Reliability Coordinator
Area, but 25% or more, but less
than 50% of these SOLs are
inconsistent with the Reliability
Coordinator’s SOL Methodology.
(R2)
The Transmission Operator has
established SOLs for its portion
of the Reliability Coordinator
Area, but 50% or more, but less
than 75% of these SOLs are
inconsistent with the Reliability
Coordinator’s SOL Methodology.
(R2)
The Transmission Operator has
established SOLs for its portion
of the Reliability Coordinator
Area, but 75% or more of these
SOLs are inconsistent with the
Reliability Coordinator’s SOL
Methodology. (R2)
R3
There are SOLs, for the Planning
Coordinator Area, but from 1% up
to, but less than, 25% of these
SOLs are inconsistent with the
Planning Coordinator’s SOL
Methodology. (R3)
There are SOLs, for the Planning
Coordinator Area, but 25% or
more, but less than 50% of these
SOLs are inconsistent with the
Planning Coordinator’s SOL
Methodology. (R3)
There are SOLs for the Planning
Coordinator Area, but 50% or
more, but less than 75% of these
SOLs are inconsistent with the
Planning Coordinator’s SOL
Methodology. (R3)
There are SOLs, for the Planning
Coordinator Area, but 75% or
more of these SOLs are
inconsistent with the Planning
Coordinator’s SOL Methodology.
(R3)
R4
The Transmission Planner has
established SOLs for its portion
of the Planning Coordinator Area,
but up to 25% of these SOLs are
inconsistent with the Planning
Coordinator’s SOL Methodology.
(R4)
The Transmission Planner has
established SOLs for its portion
of the Planning Coordinator Area,
but 25% or more, but less than
50% of these SOLs are
inconsistent with the Planning
Coordinator’s SOL Methodology.
(R4)
The Transmission Planner has
established SOLs for its portion
of the Reliability Coordinator
Area, but 50% or more, but less
than 75% of these SOLs are
inconsistent with the Planning
Coordinator’s SOL Methodology.
(R4)
The Transmission Planner has
established SOLs for its portion
of the Planning Coordinator Area,
but 75% or more of these SOLs
are inconsistent with the Planning
Coordinator’s SOL Methodology.
(R4)
R5
The responsible entity provided
its SOLs (including the subset of
SOLs that are IROLs) to all the
requesting entities but missed
meeting one or more of the
schedules by less than 15
One of the following:
The responsible entity provided
its SOLs (including the subset of
SOLs that are IROLs) to all but
one of the requesting entities
within the schedules provided.
One of the following:
The responsible entity provided
its SOLs (including the subset of
SOLs that are IROLs) to all but
two of the requesting entities
within the schedules provided.
One of the following:
The responsible entity failed to
provide its SOLs (including the
subset of SOLs that are IROLs)
to more than two of the
requesting entities within 45
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 4 of 6
Standard FAC-014-2 — Establish and Communicate System Operating Limits
Requirement
Lower
calendar days. (R5)
Moderate
(R5)
Or
The responsible entity provided
its SOLs to all the requesting
entities but missed meeting one
or more of the schedules for 15
or more but less than 30 calendar
days. (R5)
OR
The supporting information
provided with the IROLs does not
address 5.1.4
High
(R5)
Or
The responsible entity provided
its SOLs to all the requesting
entities but missed meeting one
or more of the schedules for 30
or more but less than 45 calendar
days. (R5)
OR
The supporting information
provided with the IROLs does not
address 5.1.3
Severe
calendar days of the associated
schedules. (R5)
OR
The supporting information
provided with the IROLs does not
address 5.1.1 and 5.1.2.
R6
The Planning Authority failed to
notify the Reliability Coordinator
in accordance with R6.2
Not applicable.
The Planning Authority identified
the subset of multiple
contingencies which result in
stability limits but did not provide
the list of multiple contingencies
and associated limits to one
Reliability Coordinator that
monitors the Facilities associated
with these limits. (R6.1)
The Planning Authority did not
identify the subset of multiple
contingencies which result in
stability limits. (R6)
OR
The Planning Authority identified
the subset of multiple
contingencies which result in
stability limits but did not provide
the list of multiple contingencies
and associated limits to more
than one Reliability Coordinator
that monitors the Facilities
associated with these limits.
(R6.1)
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 5 of 6
Standard FAC-014-2 — Establish and Communicate System Operating Limits
E. Regional Differences
None identified.
Version History
Version
1
Date
Action
Change Tracking
November 1,
2006
Adopted by Board of Trustees
New
Changed the effective date to January 1,
2009
Replaced Levels of Non-compliance with
Violation Severity Levels
Revised
2
2
June 24, 2008
Adopted by Board of Trustees: FERC Order
Revised
2
January 22,
2010
Updated effective date and footer to April
29, 2009 based on the March 20, 2009
FERC Order
Update
Adopted by Board of Trustees: June 24, 2008
Effective Date: April 29, 2009
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 6 of 6
Standard FAC-014-2 — Establish and Communicate System Operating Limits
Appendix QC-FAC-014-2
Provisions specific to the standard FAC-014-2 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Establish and Communicate System Operating Limits
2.
Number:
FAC-014-2
3.
Purpose:
No specific provision
4.
Applicability:
Functions
No specific provision
Facilities
Main Transmission System (RTP)
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l'énergie: Month xx, 201x
5.2.
Adoption of the appendix by the Régie de l'énergie: Month xx, 201x
5.3.Effective date of the standard and its appendix in Québec: Month xx 201x
6.5.3. Scope: Main Transmission System (MTS)
B.
Requirements
No specific provision
C.
Measures
No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Time Fframe
No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Violation Severity Levels
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 2
Standard FAC-014-2 — Establish and Communicate System Operating Limits
Appendix QC-FAC-014-2
Provisions specific to the standard FAC-014-2 applicable in Québec
E.
Regional Differences
No specific provision
Violation Risk Factor
No specific provision
Version History of the Appendix
Version
1
Date
Action
Change Tracking
Month xx, 201x
Effective date
New
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-2 of 2