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pdfExhibit A
Proposed Reliability Standard TPL-001-5
TPL-001-5 Clean Version
TPL-001-5 — Transmission System Planning Performance Requirements
A. Introduction
1.
Title:
Transmission System Planning Performance Requirements
2.
Number:
TPL-001-5
3.
Purpose: Establish Transmission system planning performance requirements
within the planning horizon to develop a Bulk Electric System (BES) that will operate
reliably over a broad spectrum of System conditions and following a wide range of
probable Contingencies.
4.
Applicability:
4.1. Functional Entity
5.
•
Planning Coordinator.
•
Transmission Planner.
Effective Date: See Implementation Plan.
B. Requirements and Measures
R1.
Each Transmission Planner and Planning Coordinator shall maintain System models
within its respective area for performing the studies needed to complete its Planning
Assessment. The models shall use data consistent with that provided in accordance
with the MOD-032 standard, supplemented by other sources as needed, including
items represented in the Corrective Action Plan, and shall represent projected System
conditions. This establishes Category P0 as the normal System condition in Table 1.
[Violation Risk Factor: High] [Time Horizon: Long-term Planning]
1.1.
System models shall represent:
1.1.1.
Existing Facilities.
1.1.2.
New planned Facilities and changes to existing Facilities.
1.1.3.
Real and reactive Load forecasts.
1.1.4.
Known commitments for Firm Transmission Service and Interchange.
1.1.5.
Resources (supply or demand side) required for Load.
M1. Each Transmission Planner and Planning Coordinator shall provide evidence, in
electronic or hard copy format, that it is maintaining System models within its
respective area, using data consistent with MOD-032, including items represented in
the Corrective Action Plan, representing projected System conditions, and that the
models represent the required information in accordance with Requirement R1.
R2.
Each Transmission Planner and Planning Coordinator shall prepare an annual Planning
Assessment of its portion of the BES. This Planning Assessment shall use current or
qualified past studies (as indicated in Requirement R2, Part 2.6), document
assumptions, and document summarized results of the steady state analyses, short
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TPL-001-5 — Transmission System Planning Performance Requirements
circuit analyses, and Stability analyses. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
2.1.
For the Planning Assessment, the Near-Term Transmission Planning Horizon
portion of the steady state analysis shall be assessed annually and be
supported by current annual studies or qualified past studies as indicated in
Requirement R2, Part 2.6. Qualifying studies need to include the following
conditions:
2.1.1.
System peak Load for either Year One or year two, and for year five.
2.1.2.
System Off-Peak Load for one of the five years.
2.1.3.
For each of the studies described in Requirement R2, Parts 2.1.1 and
2.1.2, sensitivity case(s) shall be utilized to demonstrate the impact of
changes to the basic assumptions used in the model. To accomplish
this, the sensitivity analysis in the Planning Assessment must vary one
or more of the following conditions by a sufficient amount to stress
the System within a range of credible conditions that demonstrate a
measurable change in System response :
2.1.4.
•
Real and reactive forecasted Load.
•
Expected transfers.
•
Expected in service dates of new or modified Transmission
Facilities.
•
Reactive resource capability.
•
Generation additions, retirements, or other dispatch scenarios.
•
Controllable Loads and Demand Side Management.
•
Duration or timing of known Transmission outages.
When known outage(s) of generation or Transmission Facility(ies) are
planned in the Near-Term Planning Horizon, the impact of selected
known outages on System performance shall be assessed. These
known outage(s) shall be selected for assessment consistent with a
documented outage coordination procedure or technical rationale by
the Planning Coordinator or Transmission Planner. Known outage(s)
shall not be excluded solely based upon outage duration. The
assessment shall be performed for the P0 and P1 categories
identified in Table 1 with the System peak or Off-Peak conditions that
the System is expected to experience when the known outage(s) are
planned. This assessment shall include, at a minimum known outages
expected to produce more severe System impacts on the Planning
Coordinator or Transmission Planner’s portion of the BES. Past or
current studies may support the selection of known outage(s), if the
study(s) has comparable post-Contingency System conditions and
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TPL-001-5 — Transmission System Planning Performance Requirements
configuration such as those following P3 or P6 category events in
Table 1.
2.1.5.
2.2.
When an entity’s spare equipment strategy could result in the
unavailability of major Transmission equipment that has a lead time
of one year or more (such as a transformer), the impact of this
possible unavailability on System performance shall be assessed.
Based upon this assessment, an analysis shall be performed for the
P0, P1, and P2 categories identified in Table 1 with the conditions
that the System is expected to experience during the possible
unavailability of the long lead time equipment.
For the Planning Assessment, the Long-Term Transmission Planning Horizon
portion of the steady state analysis shall be assessed annually and be
supported by the following annual current study, supplemented with
qualified past studies as indicated in Requirement R2, Part 2.6:
2.2.1. A current study assessing expected System peak Load conditions for
one of the years in the Long-Term Transmission Planning Horizon and
the rationale for why that year was selected.
2.3.
The short circuit analysis portion of the Planning Assessment shall be
conducted annually addressing the Near-Term Transmission Planning Horizon
and can be supported by current or past studies as qualified in Requirement
R2, Part 2.6. The analysis shall be used to determine whether circuit breakers
have interrupting capability for Faults that they will be expected to interrupt
using the System short circuit model with any planned generation and
Transmission Facilities in service which could impact the study area.
2.4.
For the Planning Assessment, the Near-Term Transmission Planning Horizon
portion of the Stability analysis shall be assessed annually and be supported
by current or past studies as qualified in Requirement R2, Part2.6. The
following studies are required:
2.4.1. System peak Load for one of the five years. System peak Load levels
shall include a Load model which represents the expected dynamic
behavior of Loads that could impact the study area, considering the
behavior of induction motor Loads. An aggregate System Load model
which represents the overall dynamic behavior of the Load is
acceptable.
2.4.2. System Off-Peak Load for one of the five years.
2.4.3. For each of the studies described in Requirement R2, Parts 2.4.1 and
2.4.2, sensitivity case(s) shall be utilized to demonstrate the impact of
changes to the basic assumptions used in the model. To accomplish
this, the sensitivity analysis in the Planning Assessment must vary one
or more of the following conditions by a sufficient amount to stress
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TPL-001-5 — Transmission System Planning Performance Requirements
the System within a range of credible conditions that demonstrate a
measurable change in performance:
2.5.
•
Load level, Load forecast, or dynamic Load model assumptions.
•
Expected transfers.
•
Expected in service dates of new or modified Transmission
Facilities.
•
Reactive resource capability.
•
Generation additions, retirements, or other dispatch scenarios.
2.4.4.
When known outage(s) of generation or Transmission Facility(ies) are
planned in the Near-Term Planning Horizon, the impact of selected
known outages on System performance shall be assessed. These
known outage(s) shall be selected for assessment consistent with a
documented outage coordination procedure or technical rationale by
the Planning Coordinator or Transmission Planner. Known outage(s)
shall not be excluded solely based upon outage duration. The
assessment shall be performed for the P1 categories identified in
Table 1 with the System peak or Off-Peak conditions that the System
is expected to experience when the known outage(s) are planned.
This assessment shall include, at a minimum, those known outages
expected to produce more severe System impacts on the Planning
Coordinator or Transmission Planner’s portion of the BES. Past or
current studies may support the selection of known outage(s), if the
study(s) has comparable post-Contingency System conditions and
configuration such as those following P3 or P6 category events in
Table 1.
2.4.5.
When an entity’s spare equipment strategy could result in the
unavailability of major Transmission equipment that has a lead time
of one year or more (such as a transformer), the impact of this
possible unavailability on System performance shall be assessed.
Based upon this assessment, an analysis shall be performed for the
selected P1 and P2 category events identified in Table 1 for which the
unavailability is expected to produce more severe System impacts on
its portion of the BES. The analysis shall simulate the conditions that
the System is expected to experience during the possible
unavailability of the long lead time equipment.
For the Planning Assessment, the Long-Term Transmission Planning Horizon
portion of the Stability analysis shall be assessed to address the impact of
proposed material generation additions or changes in that timeframe and be
supported by current or past studies as qualified in Requirement R2, Part2.6
and shall include documentation to support the technical rationale for
determining material changes.
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TPL-001-5 — Transmission System Planning Performance Requirements
2.6.
Past studies may be used to support the Planning Assessment if they meet
the following requirements:
2.6.1. For steady state, short circuit, or Stability analysis: the study shall be
five calendar years old or less, unless a technical rationale can be
provided to demonstrate that the results of an older study are still
valid.
2.6.2. For steady state, short circuit, or Stability analysis: no material
changes have occurred to the System represented in the study.
Documentation to support the technical rationale for determining
material changes shall be included.
2.7.
For planning events shown in Table 1, when the analysis indicates an inability
of the System to meet the performance requirements in Table 1, the Planning
Assessment shall include Corrective Action Plan(s) addressing how the
performance requirements will be met. Revisions to the Corrective Action
Plan(s) are allowed in subsequent Planning Assessments, but the planned
System shall continue to meet the performance requirements in Table 1.
Corrective Action Plan(s) do not need to be developed solely to meet the
performance requirements for a single sensitivity case analyzed in accordance
with Requirements R2, Parts 2.1.4 and 2.4.3. The Corrective Action Plan(s)
shall:
2.7.1.
List System deficiencies and the associated actions needed to achieve
required System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission
and generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or
Remedial Action Schemes.
•
Installation or modification of automatic generation tripping as a
response to a single or multiple Contingency to mitigate Stability
performance violations.
•
Installation or modification of manual and automatic generation
runback/tripping as a response to a single or multiple Contingency
to mitigate steady state performance violations.
•
Use of Operating Procedures specifying how long they will be
needed as part of the Corrective Action Plan.
•
2.7.2.
Use of rate applications, DSM, new technologies, or other
initiatives.
Include actions to resolve performance deficiencies identified in
multiple sensitivity studies or provide a rationale for why actions
were not necessary.
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TPL-001-5 — Transmission System Planning Performance Requirements
2.8.
2.7.3.
If situations arise that are beyond the control of the Transmission
Planner or Planning Coordinator that prevent the implementation of
a Corrective Action Plan in the required timeframe, then the
Transmission Planner or Planning Coordinator is permitted to utilize
Non-Consequential Load Loss and curtailment of Firm Transmission
Service to correct the situation that would normally not be permitted
in Table 1, provided that the Transmission Planner or Planning
Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated,
and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.
2.7.4.
Be reviewed in subsequent annual Planning Assessments for
continued validity and implementation status of identified System
Facilities and Operating Procedures.
For short circuit analysis, if the short circuit current interrupting duty on
circuit breakers determined in Requirement R2, Part 2.3 exceeds their
Equipment Rating, the Planning Assessment shall include a Corrective Action
Plan to address the Equipment Rating violations. The Corrective Action Plan
shall:
2.8.1.
List System deficiencies and the associated actions needed to achieve
required System performance.
2.8.2.
Be reviewed in subsequent annual Planning Assessments for
continued validity and implementation status of identified System
Facilities and Operating Procedures.
M2. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of its annual Planning Assessment, that it has
prepared an annual Planning Assessment of its portion of the BES in accordance with
Requirement R2.
R3.
For the steady state portion of the Planning Assessment, each Transmission Planner
and Planning Coordinator shall perform studies for the Near-Term and Long-Term
Transmission Planning Horizons in Requirement R2, Parts 2.1, and 2.2. The studies
shall be based on computer simulation models using data provided in Requirement
R1. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1.
Studies shall be performed for planning events to determine whether the BES
meets the performance requirements in Table 1 based on the Contingency list
created in Requirement R3, Part 3.4.
3.2.
Studies shall be performed to assess the impact of the extreme events which
are identified by the list created in Requirement R3, Part 3.5. If the analysis
concludes there is Cascading caused by the occurrence of extreme events, an
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TPL-001-5 — Transmission System Planning Performance Requirements
evaluation of possible actions designed to reduce the likelihood or mitigate
the consequences and adverse impacts of the event(s) shall be conducted.
3.3.
Contingency analyses for Requirement R3, Parts 3.1 and 3.2 shall:
3.3.1.
3.3.2.
3.4.
3.3.1.1.
Tripping of generators where simulations show generator
bus voltages or high side of the generation step up (GSU)
voltages are less than known or assumed minimum
generator steady state or ride through voltage limitations.
Include in the assessment any assumptions made.
3.3.1.2.
Tripping of Transmission elements where relay loadability
limits are exceeded.
Simulate the expected automatic operation of existing and planned
devices designed to provide steady state control of electrical system
quantities when such devices impact the study area. These devices
may include equipment such as phase-shifting transformers, load tap
changing transformers, and switched capacitors and inductors.
Those planning events in Table 1 that are expected to produce more severe
System impacts on its portion of the BES shall be identified, and a list of those
Contingencies to be evaluated for System performance in Requirement R3,
Part 3.1 created. The rationale for those Contingencies selected for evaluation
shall be available as supporting information.
3.4.1.
3.5.
Simulate the removal of all elements that the Protection System and
other automatic controls are expected to disconnect for each
Contingency without operator intervention. The analyses shall
include the impact of subsequent:
The Planning Coordinator and Transmission Planner shall coordinate
with adjacent Planning Coordinators and Transmission Planners to
ensure that Contingencies on adjacent Systems which may impact
their Systems are included in the Contingency list.
Those extreme events in Table 1 that are expected to produce more severe
System impacts shall be identified and a list created of those events to be
evaluated in Requirement R3, Part 3.2. The rationale for those Contingencies
selected for evaluation shall be available as supporting information.
M3. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of the studies utilized in preparing the Planning
Assessment, in accordance with Requirement R3.
R4.
For the Stability portion of the Planning Assessment, as described in Requirement R2,
Parts 2.4 and 2.5, each Transmission Planner and Planning Coordinator shall perform
the Contingency analyses listed in Table 1. The studies shall be based on computer
simulation models using data provided in Requirement R1. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
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TPL-001-5 — Transmission System Planning Performance Requirements
4.1.
Studies shall be performed for planning events to determine whether the BES
meets the performance requirements in Table 1 based on the Contingency list
created in Requirement R4, Part 4.4.
4.1.1.
For planning event P1: No generating unit shall pull out of
synchronism. A generator being disconnected from the System by
fault clearing action or by a Remedial Action Scheme is not
considered pulling out of synchronism.
4.1.2.
For planning events P2 through P7: When a generator pulls out of
synchronism in the simulations, the resulting apparent impedance
swings shall not result in the tripping of any Transmission system
elements other than the generating unit and its directly connected
Facilities.
4.1.3.
For planning events P1 through P7: Power oscillations shall exhibit
acceptable damping as established by the Planning Coordinator and
Transmission Planner.
4.2.
Studies shall be performed to assess the impact of the extreme events which
are identified by the list created in Requirement R4, Part 4.5. If the analysis
concludes there is Cascading caused by the occurrence of extreme events, an
evaluation of possible actions designed to reduce the likelihood or mitigate
the consequences of the event (s) shall be conducted.
4.3.
Contingency analyses for Requirement R4, Parts 4.1 and 4.2 shall :
4.3.1.
4.3.2.
Simulate the removal of all elements that the Protection System and
other automatic controls are expected to disconnect for each
Contingency without operator intervention. The analyses shall
include the impact of subsequent:
4.3.1.1.
Successful high speed (less than one second) reclosing and
unsuccessful high speed reclosing into a Fault where high
speed reclosing is utilized.
4.3.1.2.
Tripping of generators where simulations show generator
bus voltages or high side of the GSU voltages are less than
known or assumed generator low voltage ride through
capability. Include in the assessment any assumptions
made.
4.3.1.3.
Tripping of Transmission lines and transformers where
transient swings cause Protection System operation based
on generic or actual relay models.
Simulate the expected automatic operation of existing and planned
devices designed to provide dynamic control of electrical system
quantities when such devices impact the study area. These devices
may include equipment such as generation exciter control and power
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TPL-001-5 — Transmission System Planning Performance Requirements
system stabilizers, static var compensators, power flow controllers,
and DC Transmission controllers.
4.4.
Those planning events in Table 1 that are expected to produce more severe
System impacts on its portion of the BES, shall be identified, and a list created
of those Contingencies to be evaluated in Requirement R4, Part 4.1. The
rationale for those Contingencies selected for evaluation shall be available as
supporting information.
4.4.1. Each Planning Coordinator and Transmission Planner shall coordinate
with adjacent Planning Coordinators and Transmission Planners to
ensure that Contingencies on adjacent Systems which may impact
their Systems are included in the Contingency list.
4.5.
Those extreme events in Table 1 that are expected to produce more severe
System impacts shall be identified and a list created of those events to be
evaluated in Requirement R4, Part 4.2. The rationale for those Contingencies
selected for evaluation shall be available as supporting information.
M4. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of the studies utilized in preparing the Planning
Assessment in accordance with Requirement R4.
R5.
Each Transmission Planner and Planning Coordinator shall have criteria for acceptable
System steady state voltage limits, post-Contingency voltage deviations, and the
transient voltage response for its System. For transient voltage response, the criteria
shall at a minimum, specify a low voltage level and a maximum length of time that
transient voltages may remain below that level. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
M5. Each Transmission Planner and Planning Coordinator shall provide dated evidence
such as electronic or hard copies of the documentation specifying the criteria for
acceptable System steady state voltage limits, post-Contingency voltage deviations,
and the transient voltage response for its System in accordance with Requirement R5.
R6.
Each Transmission Planner and Planning Coordinator shall define and document,
within their Planning Assessment, the criteria or methodology used in the analysis to
identify System instability for conditions such as Cascading, voltage instability, or
uncontrolled islanding. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
M6. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of documentation specifying the criteria or
methodology used in the analysis to identify System instability for conditions such as
Cascading, voltage instability, or uncontrolled islanding that was utilized in preparing
the Planning Assessment in accordance with Requirement R6.
R7.
Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
determine and identify each entity’s individual and joint responsibilities for
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TPL-001-5 — Transmission System Planning Performance Requirements
performing the required studies for the Planning Assessment. [Violation Risk Factor:
Low] [Time Horizon: Long-term Planning]
M7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
provide dated documentation on roles and responsibilities, such as meeting minutes,
agreements, and e-mail correspondence that identifies that agreement has been
reached on individual and joint responsibilities for performing the required studies
and Assessments in accordance with Requirement R7.
R8.
Each Planning Coordinator and Transmission Planner shall distribute its Planning
Assessment results to adjacent Planning Coordinators and adjacent Transmission
Planners within 90 calendar days of completing its Planning Assessment, and to any
functional entity that has a reliability related need and submits a written request for
the information within 30 days of such a request. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
8.1.
If a recipient of the Planning Assessment results provides documented
comments on the results, the respective Planning Coordinator or
Transmission Planner shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M8. Each Planning Coordinator and Transmission Planner shall provide evidence, such as
email notices, documentation of updated web pages, postal receipts showing
recipient and date; or a demonstration of a public posting, that it has distributed its
Planning Assessment results to adjacent Planning Coordinators and adjacent
Transmission Planners within 90 days of having completed its Planning Assessment,
and to any functional entity who has indicated a reliability need within 30 days of a
written request and that the Planning Coordinator or Transmission Planner has
provided a documented response to comments received on Planning Assessment
results within 90 calendar days of receipt of those comments in accordance with
Requirement R8.
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TPL-001-5 — Transmission System Planning Performance Requirements
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data identified in Measures M1 through M8 or
evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
•
Each Responsible Entity shall retain evidence of each requirement in this
standard for three calendar years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
1.4. Compliance Monitoring Period and Reset Timeframe:
Not applicable.
1.5. Compliance Monitoring and Enforcement Processes:
•
Compliance Audits
•
Self-Certifications
•
Spot Checks
•
Compliance Violation Investigations
•
Self-Report
•
Complaints
1.6. Additional Compliance Information
None.
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TPL-001-5 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible entity’s
System model failed to
represent one of the
Requirement R1, Parts 1.1.1
through 1.1.5.
The responsible entity’s
System model failed to
represent two of the
Requirement R1, Parts 1.1.1
through 1.1.5.
The responsible entity’s
System model failed to
represent three of the
Requirement R1, Parts 1.1.1
through 1.1.5.
Severe VSL
The responsible entity’s
System model failed to
represent four or more of
the Requirement R1, Parts
1.1.1 through 1.1.5.
OR
The responsible entity’s
System model did not
represent projected System
conditions as described in
Requirement R1.
OR
The responsible entity’s
System model did not use
data consistent with that
provided in accordance with
the MOD-032 standard and
other sources, including
items represented in the
Corrective Action Plan.
R2.
The responsible entity failed
to comply with Requirement
R2, Part 2.6.
The responsible entity failed
to comply with Requirement
R2, Part 2.3 or Part 2.8.
The responsible entity failed
to comply with one of the
following Parts of
Requirement R2: Part 2.1,
The responsible entity failed
to comply with two or more
of the following Parts of
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TPL-001-5 — Transmission System Planning Performance Requirements
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
Part 2.2, Part 2.4, Part 2.5, or Requirement R2: Part 2.1,
Part 2.7.
Part 2.2, Part 2.4, or Part 2.7.
OR
The responsible entity does
not have a completed annual
Planning Assessment.
R3.
The responsible entity did
not identify planning events
as described in Requirement
R3, Part 3.4 or extreme
events as described in
Requirement R3, Part 3.5.
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.1 to determine that
the BES meets the
performance requirements
for one of the categories (P2
through P7) in Table 1.
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.1 to determine that
the BES meets the
performance requirements
for two of the categories (P2
through P7) in Table 1.
OR
OR
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.2 to assess the impact
of extreme events.
The responsible entity did
not perform Contingency
analysis as described in
Requirement R3, Part 3.3.
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.1 to determine that
the BES meets the
performance requirements
for three or more of the
categories (P2 through P7) in
Table 1.
OR
The responsible entity did
not perform studies to
determine that the BES
meets the performance
requirements for the P0 or
P1 categories in Table 1.
OR
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TPL-001-5 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity did
not base its studies on
computer simulation models
using data provided in
Requirement R1.
R4.
R5.
The responsible entity did
not identify planning events
as described in Requirement
R4, Part 4.4 or extreme
events as described in
Requirement R4, Part 4.5.
N/A
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.1 to determine that
the BES meets the
performance requirements
for one of the categories (P1
through P7) in Table 1.
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.1 to determine that
the BES meets the
performance requirements
for two of the categories (P1
through P7) in Table 1.
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.1 to determine that
the BES meets the
performance requirements
for three or more of the
categories (P1 through P7) in
Table 1.
OR
OR
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.2 to assess the impact
of extreme events.
The responsible entity did
not perform Contingency
analysis as described in
Requirement R4, Part 4.3.
OR
N/A
N/A
The responsible entity does
not have criteria for
acceptable System steady
state voltage limits, postContingency voltage
The responsible entity did
not base its studies on
computer simulation models
using data provided in
Requirement R1.
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TPL-001-5 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
deviations, or the transient
voltage response for its
System.
R6.
N/A
N/A
N/A
The responsible entity failed
to define and document the
criteria or methodology for
System instability used
within its analysis as
described in Requirement
R6.
R7.
N/A
N/A
N/A
The Planning Coordinator, in
conjunction with each of its
Transmission Planners, failed
to determine and identify
individual or joint
responsibilities for
performing required studies.
R8
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 90 days but
less than or equal to 120
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 120 days but
less than or equal to 130
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 130 days but
less than or equal to 140
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 140 days
following its completion.
Page 15 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
days following its
completion.
days following its
completion.
days following its
completion.
OR,
OR,
OR,
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 30 days but
less than or equal to 40 days
following the request.
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 40 days but
less than or equal to 50 days
following the request.
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 50 days but
less than or equal to 60 days
following the request.
Severe VSL
OR
The responsible entity did
not distribute its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners.
OR
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 60 days
following the request.
OR
The responsible entity did
not distribute its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing.
Page 16 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
D. Regional Variances
None.
E. Associated Documents
None.
Page 17 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Version History
Action
Change
Tracking
Version
Date
0
April 1, 2005
Effective Date
New
0
February 8,
2005
BOT Approval
Revised
0
June 3, 2005
Fixed reference in M1 to read TPL-001-0
R2.1
and TPL-001-0 R2.2
Errata
0
July 24, 2007
Corrected reference in M1. to read TPL001-0
R1 and TPL-001-0 R2.
Errata
0.1
October 29,
2008
BOT adopted errata changes; updated
version number to “0.1”
Errata
0.1
May 13,
2009
FERC Approved – Updated Effective Date
and Footer
Revised
1
Approved by
Board of
Trustees
February 17,
2011
Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009
Revised (Project
2010-11)
2
August 4,
2011
Revision of TPL-001-1; includes merging
and upgrading requirements of TPL-0010, TPL-002-0, TPL-003-0, and TPL-004-0
into one, single, comprehensive,
coordinated standard: TPL-001-2; and
retirement of TPL-005-0 and TPL-006-0.
Project 2006-02
– complete
revision
2
August 4,
2011
Adopted by Board of Trustees
1
April 19,
2012
FERC issued Order 762 remanding TPL001-1, TPL-002-1b, TPL-003-1a, and TPL004-1. FERC also issued a NOPR
proposing to remand TPL-001-2. NERC
has been directed to revise footnote 'b' in
accordance with the directives of Order
Nos. 762 and 693.
3
February 7,
2013
Adopted by the NERC Board of Trustees.
Page 18 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Version
Date
Action
Change
Tracking
TPL-001-3 was created after the Board of
Trustees approved the revised footnote
‘b’ in TPL-002-2b, which was balloted and
appended to: TPL-001-0.1, TPL-002-0b,
TPL-003-0a, and TPL-004-0.
4
February 7,
2013
Adopted by the NERC Board of Trustees.
TPL-001-4 was adopted by the Board of
Trustees as TPL-001-3, but a discrepancy
in numbering was identified and
corrected prior to filing with the
regulatory agencies.
4
October 17,
2013
FERC Order issued approving TPL-001-4
(Order effective December 23, 2013).
4
May 7, 2014
NERC Board of Trustees adopted change
to VRF in Requirement 1 from Medium to
High.
4
November
26, 2014
FERC issued a letter order approving
change to VRF in Requirement 1 from
Medium to High.
5
November 7,
2018
Adopted by the NERC Board of Trustees.
Revision
Revised to
address
reliability issues
as identified in
FERC Order No.
754 and Order
No. 786
directives and
update the
references to
the MOD
Reliability
Standards in
TPL-001.
Page 19 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a. The System shall remain stable. Cascading and uncontrolled islanding shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such adjustments
are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as established by the Planning
Coordinator and the Transmission Planner.
h. Planning event P0 is applicable to steady state only.
i.
The response of voltage sensitive Load that is disconnected from the System by end-user equipment associated with an event shall not be
used to meet steady state performance requirements.
Stability Only:
j.
Transient voltage response shall be within acceptable limits established by the Planning Coordinator and the Transmission Planner.
Page 20 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Category
P0
No
Contingency
P1
Single
Contingency
P2
Single
Contingency
Fault Type 2
BES Level 3
None
N/A
EHV, HV
No
No
Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
3Ø
EHV, HV
No9
No12
5. Single Pole of a DC line
SLG
1. Opening of a line section w/o a
fault 7
N/A
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
EHV
No9
No
HV
Yes
Yes
EHV, HV
Yes
Yes
Event 1
Initial Condition
Normal System
Normal System
2. Bus Section Fault
Normal System
NonConsequential
Load Loss
Allowed
Interruption of
Firm Transmission
Service Allowed 4
SLG
3. Internal Breaker Fault8
(non-Bus-tie Breaker)
SLG
4. Internal Breaker Fault (Bus-tie
Breaker)8
SLG
Page 21 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Category
P3
Multiple
Contingency
Initial Condition
Event 1
Loss of one of the following:
1. Generator
Loss of generator unit 2. Transmission Circuit
followed by System
3. Transformer5
adjustments9
4. Shunt Device6
5. Single pole of a DC line
P4
Multiple
Contingency
(Fault plus
stuck
breaker10)
Normal System
Loss of multiple elements caused by
a stuck breaker10(non-Bus-tie
Breaker) attempting to clear a Fault
on one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Bus Section
6. Loss of multiple elements caused
by a stuck breaker10 (Bus-tie
Breaker) attempting to clear a
Fault on the associated bus
Fault Type 2
BES Level 3
Interruption of
Firm
Transmission
Service Allowed 4
NonConsequential
Load Loss
Allowed
3Ø
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
EHV, HV
Yes
Yes
SLG
SLG
SLG
Page 22 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Initial Condition
Event 1
P5
Multiple
Contingency
(Fault plus
nonredundant
component
of a
Protection
System
failure to
operate)
Normal System
Delayed Fault Clearing due to the
failure of a non-redundant
component of a Protection System13
protecting the Faulted element to
operate as designed, for one of the
following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Bus Section
P6
Multiple
Contingency
(Two
overlapping
singles)
Loss of one of the
following followed by
System adjustments.9
1. Transmission
Circuit
2. Transformer 5
3. Shunt Device6
4. Single pole of a DC
line
Category
Loss of one of the following:
1. Transmission Circuit
2. Transformer5
3. Shunt Device6
BES Level 3
Interruption of
Firm
Transmission
Service Allowed 4
NonConsequential
Load Loss
Allowed
EHV
No9
No
HV
Yes
Yes
3Ø
EHV, HV
Yes
Yes
SLG
EHV, HV
Yes
Yes
Fault Type 2
SLG
4. Single pole of a DC line
Page 23 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Category
P7
Multiple
Contingency
(Common
Structure)
Initial Condition
Normal System
Event 1
The loss of:
1. Any two adjacent (vertically or
horizontally) circuits on
common structure 11
2. Loss of a bipolar DC line
Fault Type 2
BES Level 3
Interruption of
Firm
Transmission
Service Allowed 4
SLG
EHV, HV
Yes
NonConsequential
Load Loss
Allowed
Yes
Page 24 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Extreme Events
Steady State & Stability
For all extreme events evaluated:
a. Simulate the removal of all elements that Protection Systems and automatic controls are expected to disconnect for each Contingency.
b. Simulate Normal Clearing unless otherwise specified.
Steady State
1. Loss of a single generator, Transmission Circuit, single pole of a
DC Line, shunt device, or transformer forced out of service
followed by another single generator, Transmission Circuit,
single pole of a different DC Line, shunt device, or transformer
forced out of service prior to System adjustments.
2. Local area events affecting the Transmission System such as:
a. Loss of a tower line with three or more circuits.11
b. Loss of all Transmission lines on a common Right-ofWay11.
c. Loss of a switching station or substation (loss of one
voltage level plus transformers).
d. Loss of all generating units at a generating station.
e. Loss of a large Load or major Load center.
3. Wide area events affecting the Transmission System based on
System topology such as:
a. Loss of two generating stations resulting from
conditions such as:
i. Loss of a large gas pipeline into a region or
multiple regions that have significant gas-fired
generation.
Stability
1. With an initial condition of a single generator, Transmission
circuit, single pole of a DC line, shunt device, or transformer
forced out of service, apply a 3Ø fault on another single
generator, Transmission circuit, single pole of a different DC line,
shunt device, or transformer prior to System adjustments.
2. Local or wide area events affecting the Transmission System such
as:
a. 3Ø fault on generator with stuck breaker10 resulting in
Delayed Fault Clearing.
b. 3Ø fault on Transmission circuit with stuck breaker10
resulting in Delayed Fault Clearing.
c. 3Ø fault on transformer with stuck breaker10 resulting in
Delayed Fault Clearing.
d. 3Ø fault on bus section with stuck breaker10 resulting in
Delayed Fault Clearing.
e. 3Ø fault on generator with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
f. 3Ø fault on Transmission circuit with failure of a nonredundant component of a Protection System13 resulting
in Delayed Fault Clearing.
Page 25 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
ii. Loss of the use of a large body of water as the
cooling source for generation.
iii. Wildfires.
iv. Severe weather, e.g., hurricanes, tornadoes, etc.
v. A successful cyber attack.
vi. Shutdown of a nuclear power plant(s) and
related facilities for a day or more for common
causes such as problems with similarly designed
plants.
b. Other events based upon operating experience that may
result in wide area disturbances.
g. 3Ø fault on transformer with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
h. 3Ø fault on bus section with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
i. 3Ø internal breaker fault.
j. Other events based upon operating experience, such as
consideration of initiating events that experience
suggests may result in wide area disturbances
Page 26 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the element(s) removed for
the analyzed event determines the stated performance criteria regarding allowances for interruptions of Firm Transmission Service and NonConsequential Load Loss.
2. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that must be
evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study indicating the criteria are being met is
sufficient evidence that a SLG condition would also meet the criteria.
3. Bulk Electric System (BES) level references include extra-high voltage (EHV) Facilities defined as greater than 300kV and high voltage (HV)
Facilities defined as the 300kV and lower voltage Systems. The designation of EHV and HV is used to distinguish between stated performance
criteria allowances for interruption of Firm Transmission Service and Non-Consequential Load Loss.
4. Curtailment of Conditional Firm Transmission Service is allowed when the conditions and/or events being studied formed the basis for the
Conditional Firm Transmission Service.
5. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side winding (excluding
tertiary windings). For generator and Generator Step Up transformer outage events, the reference voltage applies to the BES connected
voltage (high-side of the Generator Step Up transformer). Requirements which are applicable to transformers also apply to variable frequency
transformers and phase shifting transformers.
6. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
7. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving Load radial
from a single source point.
8. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both sides of
the breaker.
9. An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Firm Transmission Service
following Contingency events. Curtailment of Firm Transmission Service is allowed both as a System adjustment (as identified in the column
entitled ‘Initial Condition’) and a corrective action when achieved through the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities, internal and external to the Transmission Planner’s planning region, remain within
applicable Facility Ratings and the re-dispatch does not result in any Non-Consequential Load Loss. Where limited options for re-dispatch
exist, sensitivities associated with the availability of those resources should be considered.
Page 27 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
10. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent pole
operated (IPO) or an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results in Delayed
Fault Clearing.
11. Excludes circuits that share a common structure (Planning event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event,
steady state 2b) for 1 mile or less.
12. An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following planning events.
In limited circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance
requirements are met. However, when Non-Consequential Load Loss is utilized under footnote 12 within the Near-Term Transmission
Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the Non-Consequential Load
Loss meets the conditions shown in Attachment 1. In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW
for US registered entities. The amount of planned Non-Consequential Load Loss for a non-US Registered Entity should be implemented in a
manner that is consistent with, or under the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
13. For purposes of this standard, non-redundant components of a Protection System to consider are as follows:
a. A single protective relay which responds to electrical quantities, without an alternative (which may or may not respond to electrical
quantities) that provides comparable Normal Clearing times;
b. A single communications system associated with protective functions, necessary for correct operation of a communication-aided
protection scheme required for Normal Clearing (an exception is a single communications system that is both monitored and reported at a
Control Center);
c. A single station dc supply associated with protective functions required for Normal Clearing (an exception is a single station dc supply that
is both monitored and reported at a Control Center for both low voltage and open circuit);
d. A single control circuitry (including auxiliary relays and lockout relays) associated with protective functions, from the dc supply through and
including the trip coil(s) of the circuit breakers or other interrupting devices, required for Normal Clearing (the trip coil may be excluded if
it is both monitored and reported at a Control Center).
Page 28 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Non-Consequential Load Loss under
footnote 12 is allowed as an element of a Corrective Action Plan in the Near-Term Transmission
Planning Horizon of the Planning Assessment, the Transmission Planner or Planning Coordinator
shall ensure that the utilization of footnote 12 is reviewed through an open and transparent
stakeholder process. The responsible entity can utilize an existing process or develop a new
process. .The process must include the following:
1. Meetings must be open to affected stakeholders including applicable regulatory
authorities or governing bodies responsible for retail electric service issues
2. Notice must be provided in advance of meetings to affected stakeholders including
applicable regulatory authorities or governing bodies responsible for retail electric
service issues and include an agenda with:
a. Date, time, and location for the meeting
b. Specific location(s) of the planned Non-Consequential Load Loss under footnote
12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed NonConsequential Load Loss under footnote 12 (as shown in Section II below) must be made
available to meeting participants
4. A procedure for stakeholders to submit written questions or concerns and to receive
written responses to the submitted questions and concerns
5. A dispute resolution process for any question or concern raised in #4 above that is not
resolved to the stakeholder’s satisfaction
An entity does not have to repeat the stakeholder process for a specific application of footnote
12 utilization with respect to subsequent Planning Assessments unless conditions spelled out in
Section II below have materially changed for that specific application.
II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Non-Consequential Load Loss under
footnote 12 which must include the following:
1. Conditions under which Non-Consequential Load Loss under footnote 12 would be
necessary:
a. System Load level and estimated annual hours of exposure at or above that Load
level
Page 29 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
b. Applicable Contingencies and the Facilities outside their applicable rating due to
that Contingency
2. Amount of Non-Consequential Load Loss with:
a. The estimated number and type of customers affected
b. An explanation of the effect of the use of Non-Consequential Load Loss under
footnote 12 on the health, safety, and welfare of the community
3. Estimated frequency of Non-Consequential Load Loss under footnote 12 based on
historical performance
4. Expected duration of Non-Consequential Load Loss under footnote 12 based on
historical performance
5. Future plans to alleviate the need for Non-Consequential Load Loss under footnote 12
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 12
7. Alternatives to Non-Consequential Load Loss considered and the rationale for not
selecting those alternatives under footnote 12
8. Assessment of potential overlapping uses of footnote 12 including overlaps with
adjacent Transmission Planners and Planning Coordinators
III. Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is
Required
Before a Non-Consequential Load Loss under footnote 12 is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator must ensure that the applicable regulatory authorities or governing
bodies responsible for retail electric service issues do not object to the use of NonConsequential Load Loss under footnote 12 if either:
1. The voltage level of the Contingency is greater than 300 kV
a. If the Contingency analyzed involves BES Elements at multiple System voltage
levels, the lowest System voltage level of the element(s) removed for the
analyzed Contingency determines the stated performance criteria regarding
allowances for Non-Consequential Load Loss under footnote 12, or
b. For a non-generator step up transformer outage Contingency, the 300 kV limit
applies to the low-side winding (excluding tertiary windings). For a generator or
generator step up transformer outage Contingency, the 300 kV limit applies to
the BES connected voltage (high-side of the Generator Step Up transformer)
Page 30 of 31
TPL-001-5 — Transmission System Planning Performance Requirements
2. The planned Non-Consequential Load Loss under footnote 12 is greater than or equal to
25 MW
Once assurance has been received that the applicable regulatory authorities or governing
bodies responsible for retail electric service issues do not object to the use of NonConsequential Load Loss under footnote 12, the Planning Coordinator or Transmission Planner
must submit the information outlined in items II.1 through II.8 above to the ERO for a
determination of whether there are any Adverse Reliability Impacts caused by the request to
utilize footnote 12 for Non-Consequential Load Loss.
Page 31 of 31
TPL-001-5 Redline Version
TPL-001-45 — Transmission System Planning Performance Requirements
A. Introduction
1.
Title:
Transmission System Planning Performance Requirements
2.
Number:
TPL-001-45
3.
Purpose: Establish Transmission system planning performance requirements
within the planning horizon to develop a Bulk Electric System (BES) that will operate
reliably over a broad spectrum of System conditions and following a wide range of
probable Contingencies.
4.
Applicability:
4.1. Functional Entity
5.
•
Planning Coordinator.
•
Transmission Planner.
Effective Date: See Implementation Plan.Requirements R1 and R7 as well as the
definitions shall become effective on the first day of the first calendar quarter, 12
months after applicable regulatory approval. In those jurisdictions where regulatory
approval is not required, Requirements R1 and R7 become effective on the first day of
the first calendar quarter, 12 months after Board of Trustees adoption or as otherwise
made effective pursuant to the laws applicable to such ERO governmental
authorities.
Except as indicated below, Requirements R2 through R6 and Requirement R8 shall
become effective on the first day of the first calendar quarter, 24 months after
applicable regulatory approval. In those jurisdictions where regulatory approval is not
required, all requirements, except as noted below, go into effect on the first day of
the first calendar quarter, 24 months after Board of Trustees adoption or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
For 84 calendar months beginning the first day of the first calendar quarter following
applicable regulatory approval, or in those jurisdictions where regulatory approval is
not required on the first day of the first calendar quarter 84 months after Board of
Trustees adoption or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities, Corrective Action Plans applying to the following
categories of Contingencies and events identified in TPL-001-4, Table 1 are allowed to
include Non-Consequential Load Loss and curtailment of Firm Transmission Service (in
accordance with Requirement R2, Part 2.7.3.) that would not otherwise be permitted
by the requirements of TPL-001-4:
•
P1-2 (for controlled interruption of electric supply to local network customers
connected to or supplied by the Faulted element)
•
P1-3 (for controlled interruption of electric supply to local network customers
connected to or supplied by the Faulted element)
•
P2-1
•
P2-2 (above 300 kV)
Page 1 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
•
P2-3 (above 300 kV)
•
P3-1 through P3-5
•
P4-1 through P4-5 (above 300 kV)
•
P5 (above 300 kV)
B. Requirements and Measures
R1.
Each Transmission Planner and Planning Coordinator shall maintain System models
within its respective area for performing the studies needed to complete its Planning
Assessment. The models shall use data consistent with that provided in accordance
with the MOD-010 and MOD-012 standards032 standard, supplemented by other
sources as needed, including items represented in the Corrective Action Plan, and
shall represent projected System conditions. This establishes Category P0 as the
normal System condition in Table 1. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
1.1.
System models shall represent:
1.1.1.
Existing Facilities.
1.1.2.
Known outage(s) of generation or Transmission Facility(ies) with a
duration of at least six months.
1.1.3.1.1.2. New planned Facilities and changes to existing Facilities.
1.1.4.1.1.3.
Real and reactive Load forecasts.
1.1.5.1.1.4.
Known commitments for Firm Transmission Service and
Interchange.
1.1.6.1.1.5.
Resources (supply or demand side) required for Load.
M1. Each Transmission Planner and Planning Coordinator shall provide evidence, in
electronic or hard copy format, that it is maintaining System models within their its
respective area, using data consistent with MOD-010 and MOD-012032, including
items represented in the Corrective Action Plan, representing projected System
conditions, and that the models represent the required information in accordance
with Requirement R1.
R2.
Each Transmission Planner and Planning Coordinator shall prepare an annual Planning
Assessment of its portion of the BES. This Planning Assessment shall use current or
qualified past studies (as indicated in Requirement R2, Part 2.6), document
assumptions, and document summarized results of the steady state analyses, short
circuit analyses, and Stability analyses. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
2.1.
For the Planning Assessment, the Near-Term Transmission Planning Horizon
portion of the steady state analysis shall be assessed annually and be
supported by current annual studies or qualified past studies as indicated in
Page 2 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Requirement R2, Part 2.6. Qualifying studies need to include the following
conditions:
2.1.1.
System peak Load for either Year One or year two, and for year five.
2.1.2.
System Off-Peak Load for one of the five years.
2.1.3.
P1 events in Table 1, with known outages modeled as in Requirement
R1, Part 1.1.2, under those System peak or Off-Peak conditions when
known outages are scheduled.
2.1.4.2.1.3. For each of the studies described in Requirement R2, Parts 2.1.1
and 2.1.2, sensitivity case(s) shall be utilized to demonstrate the
impact of changes to the basic assumptions used in the model. To
accomplish this, the sensitivity analysis in the Planning Assessment
must vary one or more of the following conditions by a sufficient
amount to stress the System within a range of credible conditions
that demonstrate a measurable change in System response :
2.1.4.
•
Real and reactive forecasted Load.
•
Expected transfers.
•
Expected in service dates of new or modified Transmission
Facilities.
•
Reactive resource capability.
•
Generation additions, retirements, or other dispatch scenarios.
•
Controllable Loads and Demand Side Management.
•
Duration or timing of known Transmission outages.
When known outage(s) of generation or Transmission Facility(ies) are
planned in the Near-Term Planning Horizon, the impact of selected
known outages on System performance shall be assessed. These
known outage(s) shall be selected for assessment consistent with a
documented outage coordination procedure or technical rationale by
the Planning Coordinator or Transmission Planner. Known outage(s)
shall not be excluded solely based upon outage duration. The
assessment shall be performed for the P0 and P1 categories
identified in Table 1 with the System peak or Off-Peak conditions that
the System is expected to experience when the known outage(s) are
planned. This assessment shall include, at a minimum known outages
expected to produce more severe System impacts on the Planning
Coordinator or Transmission Planner’s portion of the BES. Past or
current studies may support the selection of known outage(s), if the
study(s) has comparable post-Contingency System conditions and
configuration such as those following P3 or P6 category events in
Table 1.
Page 3 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
2.1.5.
2.2.
When an entity’s spare equipment strategy could result in the
unavailability of major Transmission equipment that has a lead time
of one year or more (such as a transformer), the impact of this
possible unavailability on System performance shall be
studiedassessed. Based upon this assessment, anThe studies analysis
shall be performed for the P0, P1, and P2 categories identified in
Table 1 with the conditions that the System is expected to experience
during the possible unavailability of the long lead time equipment.
For the Planning Assessment, the Long-Term Transmission Planning Horizon
portion of the steady state analysis shall be assessed annually and be
supported by the following annual current study, supplemented with
qualified past studies as indicated in Requirement R2, Part 2.6:
2.2.1. A current study assessing expected System peak Load conditions for
one of the years in the Long-Term Transmission Planning Horizon and
the rationale for why that year was selected.
2.3.
The short circuit analysis portion of the Planning Assessment shall be
conducted annually addressing the Near-Term Transmission Planning Horizon
and can be supported by current or past studies as qualified in Requirement
R2, Part 2.6. The analysis shall be used to determine whether circuit breakers
have interrupting capability for Faults that they will be expected to interrupt
using the System short circuit model with any planned generation and
Transmission Facilities in service which could impact the study area.
2.4.
For the Planning Assessment, the Near-Term Transmission Planning Horizon
portion of the Stability analysis shall be assessed annually and be supported
by current or past studies as qualified in Requirement R2, Part2.6. The
following studies are required:
2.4.1. System peak Load for one of the five years. System peak Load levels
shall include a Load model which represents the expected dynamic
behavior of Loads that could impact the study area, considering the
behavior of induction motor Loads. An aggregate System Load model
which represents the overall dynamic behavior of the Load is
acceptable.
2.4.2. System Off-Peak Load for one of the five years.
2.4.3. For each of the studies described in Requirement R2, Parts 2.4.1 and
2.4.2, sensitivity case(s) shall be utilized to demonstrate the impact of
changes to the basic assumptions used in the model. To accomplish
this, the sensitivity analysis in the Planning Assessment must vary one
or more of the following conditions by a sufficient amount to stress
the System within a range of credible conditions that demonstrate a
measurable change in performance:
Page 4 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
•
Load level, Load forecast, or dynamic Load model assumptions.
•
Expected transfers.
•
Expected in service dates of new or modified Transmission
Facilities.
•
Reactive resource capability.
•
Generation additions, retirements, or other dispatch scenarios.
2.4.4.
When known outage(s) of generation or Transmission Facility(ies) are
planned in the Near-Term Planning Horizon, the impact of selected
known outages on System performance shall be assessed. These
known outage(s) shall be selected for assessment consistent with a
documented outage coordination procedure or technical rationale by
the Planning Coordinator or Transmission Planner. Known outage(s)
shall not be excluded solely based upon outage duration. The
assessment shall be performed for the P1 categories identified in
Table 1 with the System peak or Off-Peak conditions that the System
is expected to experience when the known outage(s) are planned.
This assessment shall include, at a minimum, those known outages
expected to produce more severe System impacts on the Planning
Coordinator or Transmission Planner’s portion of the BES. Past or
current studies may support the selection of known outage(s), if the
study(s) has comparable post-Contingency System conditions and
configuration such as those following P3 or P6 category events in
Table 1.
2.4.5.
When an entity’s spare equipment strategy could result in the
unavailability of major Transmission equipment that has a lead time
of one year or more (such as a transformer), the impact of this
possible unavailability on System performance shall be assessed.
Based upon this assessment, an analysis shall be performed for the
selected P1 and P2 category events identified in Table 1 for which the
unavailability is expected to produce more severe System impacts on
its portion of the BES. The analysis shall simulate the conditions that
the System is expected to experience during the possible
unavailability of the long lead time equipment.
2.5.
For the Planning Assessment, the Long-Term Transmission Planning Horizon
portion of the Stability analysis shall be assessed to address the impact of
proposed material generation additions or changes in that timeframe and be
supported by current or past studies as qualified in Requirement R2, Part2.6
and shall include documentation to support the technical rationale for
determining material changes.
2.6.
Past studies may be used to support the Planning Assessment if they meet
the following requirements:
Page 5 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
2.6.1. For steady state, short circuit, or Stability analysis: the study shall be
five calendar years old or less, unless a technical rationale can be
provided to demonstrate that the results of an older study are still
valid.
2.6.2. For steady state, short circuit, or Stability analysis: no material
changes have occurred to the System represented in the study.
Documentation to support the technical rationale for determining
material changes shall be included.
2.7.
For planning events shown in Table 1, when the analysis indicates an inability
of the System to meet the performance requirements in Table 1, the Planning
Assessment shall include Corrective Action Plan(s) addressing how the
performance requirements will be met. Revisions to the Corrective Action
Plan(s) are allowed in subsequent Planning Assessments, but the planned
System shall continue to meet the performance requirements in Table 1.
Corrective Action Plan(s) do not need to be developed solely to meet the
performance requirements for a single sensitivity case analyzed in accordance
with Requirements R2, Parts 2.1.4 and 2.4.3. The Corrective Action Plan(s)
shall:
2.7.1.
List System deficiencies and the associated actions needed to achieve
required System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission
and generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or
Special Protection SystemsRemedial Action Schemes.
•
Installation or modification of automatic generation tripping as a
response to a single or multiple Contingency to mitigate Stability
performance violations.
•
Installation or modification of manual and automatic generation
runback/tripping as a response to a single or multiple Contingency
to mitigate steady state performance violations.
•
Use of Operating Procedures specifying how long they will be
needed as part of the Corrective Action Plan.
•
2.7.2.
2.7.3.
Use of rate applications, DSM, new technologies, or other
initiatives.
Include actions to resolve performance deficiencies identified in
multiple sensitivity studies or provide a rationale for why actions
were not necessary.
If situations arise that are beyond the control of the Transmission
Planner or Planning Coordinator that prevent the implementation of
a Corrective Action Plan in the required timeframe, then the
Page 6 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Transmission Planner or Planning Coordinator is permitted to utilize
Non-Consequential Load Loss and curtailment of Firm Transmission
Service to correct the situation that would normally not be permitted
in Table 1, provided that the Transmission Planner or Planning
Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated,
and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.
2.7.4.
2.8.
Be reviewed in subsequent annual Planning Assessments for
continued validity and implementation status of identified System
Facilities and Operating Procedures.
For short circuit analysis, if the short circuit current interrupting duty on
circuit breakers determined in Requirement R2, Part 2.3 exceeds their
Equipment Rating, the Planning Assessment shall include a Corrective Action
Plan to address the Equipment Rating violations. The Corrective Action Plan
shall:
2.8.1.
List System deficiencies and the associated actions needed to achieve
required System performance.
2.8.2.
Be reviewed in subsequent annual Planning Assessments for
continued validity and implementation status of identified System
Facilities and Operating Procedures.
M2. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of its annual Planning Assessment, that it has
prepared an annual Planning Assessment of its portion of the BES in accordance with
Requirement R2.
R3.
For the steady state portion of the Planning Assessment, each Transmission Planner
and Planning Coordinator shall perform studies for the Near-Term and Long-Term
Transmission Planning Horizons in Requirement R2, Parts 2.1, and 2.2. The studies
shall be based on computer simulation models using data provided in Requirement
R1. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
3.1.
Studies shall be performed for planning events to determine whether the BES
meets the performance requirements in Table 1 based on the Contingency list
created in Requirement R3, Part 3.4.
3.2.
Studies shall be performed to assess the impact of the extreme events which
are identified by the list created in Requirement R3, Part 3.5. If the analysis
concludes there is Cascading caused by the occurrence of extreme events, an
evaluation of possible actions designed to reduce the likelihood or mitigate
the consequences and adverse impacts of the event(s) shall be conducted.
3.3.
Contingency analyses for Requirement R3, Parts 3.1 &and 3.2 shall:
Page 7 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
3.3.1.
3.3.2.
3.4.
3.3.1.1.
Tripping of generators where simulations show generator
bus voltages or high side of the generation step up (GSU)
voltages are less than known or assumed minimum
generator steady state or ride through voltage limitations.
Include in the assessment any assumptions made.
3.3.1.2.
Tripping of Transmission elements where relay loadability
limits are exceeded.
Simulate the expected automatic operation of existing and planned
devices designed to provide steady state control of electrical system
quantities when such devices impact the study area. These devices
may include equipment such as phase-shifting transformers, load tap
changing transformers, and switched capacitors and inductors.
Those planning events in Table 1 that are expected to produce more severe
System impacts on its portion of the BES shall be identified, and a list of those
Contingencies to be evaluated for System performance in Requirement R3,
Part 3.1 created. The rationale for those Contingencies selected for evaluation
shall be available as supporting information.
3.4.1.
3.5.
Simulate the removal of all elements that the Protection System and
other automatic controls are expected to disconnect for each
Contingency without operator intervention. The analyses shall
include the impact of subsequent:
The Planning Coordinator and Transmission Planner shall coordinate
with adjacent Planning Coordinators and Transmission Planners to
ensure that Contingencies on adjacent Systems which may impact
their Systems are included in the Contingency list.
Those extreme events in Table 1 that are expected to produce more severe
System impacts shall be identified and a list created of those events to be
evaluated in Requirement R3, Part 3.2. The rationale for those Contingencies
selected for evaluation shall be available as supporting information. If the
analysis concludes there is Cascading caused by the occurrence of extreme
events, an evaluation of possible actions designed to reduce the likelihood or
mitigate the consequences and adverse impacts of the event(s) shall be
conducted.
M3. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of the studies utilized in preparing the Planning
Assessment, in accordance with Requirement R3.
R4.
For the Stability portion of the Planning Assessment, as described in Requirement R2,
Parts 2.4 and 2.5, each Transmission Planner and Planning Coordinator shall perform
the Contingency analyses listed in Table 1. The studies shall be based on computer
Page 8 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
simulation models using data provided in Requirement R1.
Medium] [Time Horizon: Long-term Planning]
4.1.
[Violation Risk Factor:
Studies shall be performed for planning events to determine whether the BES
meets the performance requirements in Table 1 based on the Contingency list
created in Requirement R4, Part 4.4.
4.1.1.
For planning event P1: No generating unit shall pull out of
synchronism. A generator being disconnected from the System by
fault clearing action or by a Special Protection System Remedial
Action Scheme is not considered pulling out of synchronism.
4.1.2.
For planning events P2 through P7: When a generator pulls out of
synchronism in the simulations, the resulting apparent impedance
swings shall not result in the tripping of any Transmission system
elements other than the generating unit and its directly connected
Facilities.
4.1.3.
For planning events P1 through P7: Power oscillations shall exhibit
acceptable damping as established by the Planning Coordinator and
Transmission Planner.
4.2.
Studies shall be performed to assess the impact of the extreme events which
are identified by the list created in Requirement R4, Part 4.5. If the analysis
concludes there is Cascading caused by the occurrence of extreme events, an
evaluation of possible actions designed to reduce the likelihood or mitigate
the consequences of the event (s) shall be conducted.
4.3.
Contingency analyses for Requirement R4, Parts 4.1 and 4.2 shall :
4.3.1.
Simulate the removal of all elements that the Protection System and
other automatic controls are expected to disconnect for each
Contingency without operator intervention. The analyses shall
include the impact of subsequent:
4.3.1.1.
Successful high speed (less than one second) reclosing and
unsuccessful high speed reclosing into a Fault where high
speed reclosing is utilized.
4.3.1.2.
Tripping of generators where simulations show generator
bus voltages or high side of the GSU voltages are less than
known or assumed generator low voltage ride through
capability. Include in the assessment any assumptions
made.
4.3.1.3.
Tripping of Transmission lines and transformers where
transient swings cause Protection System operation based
on generic or actual relay models.
Page 9 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
4.3.2.
4.4.
Simulate the expected automatic operation of existing and planned
devices designed to provide dynamic control of electrical system
quantities when such devices impact the study area. These devices
may include equipment such as generation exciter control and power
system stabilizers, static var compensators, power flow controllers,
and DC Transmission controllers.
Those planning events in Table 1 that are expected to produce more severe
System impacts on its portion of the BES, shall be identified, and a list created
of those Contingencies to be evaluated in Requirement R4, Part 4.1. The
rationale for those Contingencies selected for evaluation shall be available as
supporting information.
4.4.1. Each Planning Coordinator and Transmission Planner shall coordinate
with adjacent Planning Coordinators and Transmission Planners to
ensure that Contingencies on adjacent Systems which may impact
their Systems are included in the Contingency list.
4.5.
Those extreme events in Table 1 that are expected to produce more severe
System impacts shall be identified and a list created of those events to be
evaluated in Requirement R4, Part 4.2. The rationale for those Contingencies
selected for evaluation shall be available as supporting information. If the
analysis concludes there is Cascading caused by the occurrence of extreme
events, an evaluation of possible actions designed to reduce the likelihood or
mitigate the consequences of the event(s) shall be conducted.
M4. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of the studies utilized in preparing the Planning
Assessment in accordance with Requirement R4.
R5.
Each Transmission Planner and Planning Coordinator shall have criteria for acceptable
System steady state voltage limits, post-Contingency voltage deviations, and the
transient voltage response for its System. For transient voltage response, the criteria
shall at a minimum, specify a low voltage level and a maximum length of time that
transient voltages may remain below that level. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
M5. Each Transmission Planner and Planning Coordinator shall provide dated evidence
such as electronic or hard copies of the documentation specifying the criteria for
acceptable System steady state voltage limits, post-Contingency voltage deviations,
and the transient voltage response for its System in accordance with Requirement R5.
R6.
Each Transmission Planner and Planning Coordinator shall define and document,
within their Planning Assessment, the criteria or methodology used in the analysis to
identify System instability for conditions such as Cascading, voltage instability, or
uncontrolled islanding. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
Page 10 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
M6. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of documentation specifying the criteria or
methodology used in the analysis to identify System instability for conditions such as
Cascading, voltage instability, or uncontrolled islanding that was utilized in preparing
the Planning Assessment in accordance with Requirement R6.
R7.
Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
determine and identify each entity’s individual and joint responsibilities for
performing the required studies for the Planning Assessment. [Violation Risk Factor:
Low] [Time Horizon: Long-term Planning]
M7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
provide dated documentation on roles and responsibilities, such as meeting minutes,
agreements, and e-mail correspondence that identifies that agreement has been
reached on individual and joint responsibilities for performing the required studies
and Assessments in accordance with Requirement R7.
R8.
Each Planning Coordinator and Transmission Planner shall distribute its Planning
Assessment results to adjacent Planning Coordinators and adjacent Transmission
Planners within 90 calendar days of completing its Planning Assessment, and to any
functional entity that has a reliability related need and submits a written request for
the information within 30 days of such a request. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
8.1.
If a recipient of the Planning Assessment results provides documented
comments on the results, the respective Planning Coordinator or
Transmission Planner shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M8. Each Planning Coordinator and Transmission Planner shall provide evidence, such as
email notices, documentation of updated web pages, postal receipts showing
recipient and date; or a demonstration of a public posting, that it has distributed its
Planning Assessment results to adjacent Planning Coordinators and adjacent
Transmission Planners within 90 days of having completed its Planning Assessment,
and to any functional entity who has indicated a reliability need within 30 days of a
written request and that the Planning Coordinator or Transmission Planner has
provided a documented response to comments received on Planning Assessment
results within 90 calendar days of receipt of those comments in accordance with
Requirement R8.
Page 11 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data identified in Measures M1 through M8 or
evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
•
Each Responsible Entity shall retain evidence of each requirement in this
standard for three calendar years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
1.4. Compliance Monitoring Period and Reset Timeframe:
Not applicable.
1.5. Compliance Monitoring and Enforcement Processes:
•
Compliance Audits
•
Self-Certifications
•
Spot Checks
•
Compliance Violation Investigations
•
Self-Report
•
Complaints
1.6. Additional Compliance Information
None.
Page 12 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible entity’s
System model failed to
represent one of the
Requirement R1, Parts 1.1.1
through 1.1.65.
The responsible entity’s
System model failed to
represent two of the
Requirement R1, Parts 1.1.1
through 1.1.65.
The responsible entity’s
System model failed to
represent three of the
Requirement R1, Parts 1.1.1
through 1.1.65.
Severe VSL
The responsible entity’s System model
failed to represent four or more of the
Requirement R1, Parts 1.1.1 through
1.1.65.
OR
The responsible entity’s System model
did not represent projected System
conditions as described in Requirement
R1.
OR
The responsible entity’s System model
did not use data consistent with that
provided in accordance with the MOD010 and MOD-012032 standards and other
sources, including items represented in
the Corrective Action Plan.
R2.
The responsible entity failed
to comply with Requirement
R2, Part 2.6.
The responsible entity failed
to comply with Requirement
R2, Part 2.3 or Part 2.8.
The responsible entity failed
to comply with one of the
following Parts of
Requirement R2: Part 2.1,
Part 2.2, Part 2.4, Part 2.5, or
Part 2.7.
Page 13 of 31
The responsible entity failed to comply
with two or more of the following Parts
of Requirement R2: Part 2.1, Part 2.2,
Part 2.4, or Part 2.7.
OR
TPL-001-45 — Transmission System Planning Performance Requirements
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity does not have a
completed annual Planning Assessment.
R3.
R4.
The responsible entity did
not identify planning events
as described in Requirement
R3, Part 3.4 or extreme
events as described in
Requirement R3, Part 3.5.
The responsible entity did
not identify planning events
as described in Requirement
R4, Part 4.4 or extreme
events as described in
Requirement R4, Part 4.5.
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.1 to determine that
the BES meets the
performance requirements
for one of the categories (P2
through P7) in Table 1.
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.1 to determine that
the BES meets the
performance requirements
for two of the categories (P2
through P7) in Table 1.
OR
OR
The responsible entity did
not perform studies as
specified in Requirement R3,
Part 3.2 to assess the impact
of extreme events.
The responsible entity did
not perform Contingency
analysis as described in
Requirement R3, Part 3.3.
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.1 to determine that
the BES meets the
performance requirements
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.1 to determine that
the BES meets the
performance requirements
The responsible entity did not perform
studies as specified in Requirement R3,
Part 3.1 to determine that the BES meets
the performance requirements for three
or more of the categories (P2 through
P7) in Table 1.
OR
The responsible entity did not perform
studies to determine that the BES meets
the performance requirements for the
P0 or P1 categories in Table 1.
OR
The responsible entity did not base its
studies on computer simulation models
using data provided in Requirement R1.
The responsible entity did not perform
studies as specified in Requirement R4,
Part 4.1 to determine that the BES meets
the performance requirements for three
or more of the categories (P1 through
P7) in Table 1.
OR
Page 14 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
for one of the categories (P1
through P7) in Table 1.
for two of the categories (P1
through P7) in Table 1.
OR
OR
The responsible entity did
not perform studies as
specified in Requirement R4,
Part 4.2 to assess the impact
of extreme events.
The responsible entity did
not perform Contingency
analysis as described in
Requirement R4, Part 4.3.
Severe VSL
The responsible entity did not base its
studies on computer simulation models
using data provided in Requirement R1.
R5.
N/A
N/A
N/A
The responsible entity does not have
criteria for acceptable System steady
state voltage limits, post-Contingency
voltage deviations, or the transient
voltage response for its System.
R6.
N/A
N/A
N/A
The responsible entity failed to define
and document the criteria or
methodology for System instability used
within its analysis as described in
Requirement R6.
R7.
N/A
N/A
N/A
The Planning Coordinator, in conjunction
with each of its Transmission Planners,
failed to determine and identify
individual or joint responsibilities for
performing required studies.
Page 15 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Violation Severity Levels
R#
R8
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 90 days but
less than or equal to 120
days following its
completion.
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 120 days but
less than or equal to 130
days following its
completion.
The responsible entity
distributed its Planning
Assessment results to
adjacent Planning
Coordinators and adjacent
Transmission Planners but it
was more than 130 days but
less than or equal to 140
days following its
completion.
The responsible entity distributed its
Planning Assessment results to adjacent
Planning Coordinators and adjacent
Transmission Planners but it was more
than 140 days following its completion.
OR,
OR,
OR,
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 30 days but
less than or equal to 40 days
following the request.
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 40 days but
less than or equal to 50 days
following the request.
The responsible entity
distributed its Planning
Assessment results to
functional entities having a
reliability related need who
requested the Planning
Assessment in writing but it
was more than 50 days but
less than or equal to 60 days
following the request.
Page 16 of 31
OR
The responsible entity did not distribute
its Planning Assessment results to
adjacent Planning Coordinators and
adjacent Transmission Planners.
OR
The responsible entity distributed its
Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing but it
was more than 60 days following the
request.
OR
The responsible entity did not distribute
its Planning Assessment results to
functional entities having a reliability
related need who requested the
Planning Assessment in writing.
TPL-001-45 — Transmission System Planning Performance Requirements
B.D.
Regional Variances
None.
E. Associated Documents
None.
Page 17 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Version History
Action
Change
Tracking
Version
Date
0
April 1, 2005
Effective Date
New
0
February 8,
2005
BOT Approval
Revised
0
June 3, 2005
Fixed reference in M1 to read TPL-001-0
R2.1
and TPL-001-0 R2.2
Errata
0
July 24, 2007
Corrected reference in M1. to read TPL001-0
R1 and TPL-001-0 R2.
Errata
0.1
October 29,
2008
BOT adopted errata changes; updated
version number to “0.1”
Errata
0.1
May 13,
2009
FERC Approved – Updated Effective Date
and Footer
Revised
1
Approved by
Board of
Trustees
February 17,
2011
Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009
Revised (Project
2010-11)
2
August 4,
2011
Revision of TPL-001-1; includes merging
and upgrading requirements of TPL-0010, TPL-002-0, TPL-003-0, and TPL-004-0
into one, single, comprehensive,
coordinated standard: TPL-001-2; and
retirement of TPL-005-0 and TPL-006-0.
Project 2006-02
– complete
revision
2
August 4,
2011
Adopted by Board of Trustees
1
April 19,
2012
FERC issued Order 762 remanding TPL001-1, TPL-002-1b, TPL-003-1a, and TPL004-1. FERC also issued a NOPR
proposing to remand TPL-001-2. NERC
has been directed to revise footnote 'b' in
accordance with the directives of Order
Nos. 762 and 693.
3
February 7,
2013
Adopted by the NERC Board of Trustees.
Page 18 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Version
Date
Action
Change
Tracking
TPL-001-3 was created after the Board of
Trustees approved the revised footnote
‘b’ in TPL-002-2b, which was balloted and
appended to: TPL-001-0.1, TPL-002-0b,
TPL-003-0a, and TPL-004-0.
4
February 7,
2013
Adopted by the NERC Board of Trustees.
TPL-001-4 was adopted by the Board of
Trustees as TPL-001-3, but a discrepancy
in numbering was identified and
corrected prior to filing with the
regulatory agencies.
4
October 17,
2013
FERC Order issued approving TPL-001-4
(Order effective December 23, 2013).
4
May 7, 2014
NERC Board of Trustees adopted change
to VRF in Requirement 1 from Medium to
High.
4
November
26, 2014
FERC issued a letter order approving
change to VRF in Requirement 1 from
Medium to High.
5
TBD
Adopted by the NERC Board of Trustees.
Revision
Revised To
address
reliability issues
as identified in
FERC Order No.
754 and Order
No. 786
directives and
update the
references to
the MOD
Reliability
Standards in
TPL-001.
Page 19 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a. The System shall remain stable. Cascading and uncontrolled islanding shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such adjustments
are executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as established by the Planning
Coordinator and the Transmission Planner.
h. Planning event P0 is applicable to steady state only.
i.
The response of voltage sensitive Load that is disconnected from the System by end-user equipment associated with an event shall not be
used to meet steady state performance requirements.
Stability Only:
j.
Transient voltage response shall be within acceptable limits established by the Planning Coordinator and the Transmission Planner.
Page 20 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Category
P0
No
Contingency
P1
Single
Contingency
P2
Single
Contingency
Fault Type 2
BES Level 3
None
N/A
EHV, HV
No
No
Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
3Ø
EHV, HV
No9
No12
5. Single Pole of a DC line
SLG
1. Opening of a line section w/o a
fault 7
N/A
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
EHV
No9
No
HV
Yes
Yes
EHV, HV
Yes
Yes
Event 1
Initial Condition
Normal System
Normal System
2. Bus Section Fault
Normal System
NonConsequential
Load Loss
Allowed
Interruption of
Firm Transmission
Service Allowed 4
SLG
3. Internal Breaker Fault8
(non-Bus-tie Breaker)
SLG
4. Internal Breaker Fault (Bus-tie
Breaker)8
SLG
Page 21 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Category
P3
Multiple
Contingency
Initial Condition
Event 1
Loss of one of the following:
1. Generator
Loss of generator unit 2. Transmission Circuit
followed by System
3. Transformer5
adjustments9
4. Shunt Device6
5. Single pole of a DC line
P4
Multiple
Contingency
(Fault plus
stuck
breaker10)
Normal System
Loss of multiple elements caused by
a stuck breaker10(non-Bus-tie
Breaker) attempting to clear a Fault
on one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Bus Section
6. Loss of multiple elements caused
by a stuck breaker10 (Bus-tie
Breaker) attempting to clear a
Fault on the associated bus
Fault Type 2
BES Level 3
Interruption of
Firm
Transmission
Service Allowed 4
NonConsequential
Load Loss
Allowed
3Ø
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
EHV, HV
Yes
Yes
SLG
SLG
SLG
Page 22 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Initial Condition
Event 1
P5
Multiple
Contingency
(Fault plus
relaynonredundant
component
of a
Protection
System
failure to
operate)
Normal System
Delayed Fault Clearing due to the
failure of a non-redundant
relay13component of a Protection
System13 protecting the Faulted
element to operate as designed, for
one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Bus Section
P6
Multiple
Contingency
(Two
overlapping
singles)
Loss of one of the
following followed by
System adjustments.9
1. Transmission
Circuit
2. Transformer 5
3. Shunt Device6
4. Single pole of a DC
line
Category
Loss of one of the following:
1. Transmission Circuit
2. Transformer5
3. Shunt Device6
BES Level 3
Interruption of
Firm
Transmission
Service Allowed 4
NonConsequential
Load Loss
Allowed
EHV
No9
No
HV
Yes
Yes
3Ø
EHV, HV
Yes
Yes
SLG
EHV, HV
Yes
Yes
Fault Type 2
SLG
4. Single pole of a DC line
Page 23 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Category
P7
Multiple
Contingency
(Common
Structure)
Initial Condition
Normal System
Event 1
The loss of:
1. Any two adjacent (vertically or
horizontally) circuits on
common structure 11
2. Loss of a bipolar DC line
Fault Type 2
BES Level 3
Interruption of
Firm
Transmission
Service Allowed 4
SLG
EHV, HV
Yes
NonConsequential
Load Loss
Allowed
Yes
Page 24 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Extreme Events
Steady State & Stability
For all extreme events evaluated:
a. Simulate the removal of all elements that Protection Systems and automatic controls are expected to disconnect for each Contingency.
b. Simulate Normal Clearing unless otherwise specified.
Steady State
1. Loss of a single generator, Transmission Circuit, single pole of a
DC Line, shunt device, or transformer forced out of service
followed by another single generator, Transmission Circuit,
single pole of a different DC Line, shunt device, or transformer
forced out of service prior to System adjustments.
2. Local area events affecting the Transmission System such as:
a. Loss of a tower line with three or more circuits.11
b. Loss of all Transmission lines on a common Right-ofWay11.
c. Loss of a switching station or substation (loss of one
voltage level plus transformers).
d. Loss of all generating units at a generating station.
e. Loss of a large Load or major Load center.
3. Wide area events affecting the Transmission System based on
System topology such as:
a. Loss of two generating stations resulting from
conditions such as:
i. Loss of a large gas pipeline into a region or
multiple regions that have significant gas-fired
generation.
Stability
1. With an initial condition of a single generator, Transmission
circuit, single pole of a DC line, shunt device, or transformer
forced out of service, apply a 3Ø fault on another single
generator, Transmission circuit, single pole of a different DC line,
shunt device, or transformer prior to System adjustments.
2. Local or wide area events affecting the Transmission System such
as:
a. 3Ø fault on generator with stuck breaker10 or a relay
failure13 resulting in Delayed Fault Clearing.
b. 3Ø fault on Transmission circuit with stuck breaker10 or a
relay failure13 resulting in Delayed Fault Clearing.
c. 3Ø fault on transformer with stuck breaker10 or a relay
failure13 resulting in Delayed Fault Clearing.
d. 3Ø fault on bus section with stuck breaker10 or a relay
failure13 resulting in Delayed Fault Clearing.
e. 3Ø fault on generator with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
f. 3Ø fault on Transmission circuit with failure of a nonredundant component of a Protection System13 resulting
in Delayed Fault Clearing.
Page 25 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
ii. Loss of the use of a large body of water as the
cooling source for generation.
iii. Wildfires.
iv. Severe weather, e.g., hurricanes, tornadoes, etc.
v. A successful cyber attack.
vi. Shutdown of a nuclear power plant(s) and
related facilities for a day or more for common
causes such as problems with similarly designed
plants.
b. Other events based upon operating experience that may
result in wide area disturbances.
g. 3Ø fault on transformer with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
h. 3Ø fault on bus section with failure of a non-redundant
component of a Protection System13 resulting in Delayed
Fault Clearing.
e.i. 3Ø internal breaker fault.
f.j. Other events based upon operating experience, such as
consideration of initiating events that experience
suggests may result in wide area disturbances
Page 26 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the element(s) removed for
the analyzed event determines the stated performance criteria regarding allowances for interruptions of Firm Transmission Service and NonConsequential Load Loss.
2. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that must be
evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study indicating the criteria are being met is
sufficient evidence that a SLG condition would also meet the criteria.
3. Bulk Electric System (BES) level references include extra-high voltage (EHV) Facilities defined as greater than 300kV and high voltage (HV)
Facilities defined as the 300kV and lower voltage Systems. The designation of EHV and HV is used to distinguish between stated performance
criteria allowances for interruption of Firm Transmission Service and Non-Consequential Load Loss.
4. Curtailment of Conditional Firm Transmission Service is allowed when the conditions and/or events being studied formed the basis for the
Conditional Firm Transmission Service.
5. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side winding (excluding
tertiary windings). For generator and Generator Step Up transformer outage events, the reference voltage applies to the BES connected
voltage (high-side of the Generator Step Up transformer). Requirements which are applicable to transformers also apply to variable frequency
transformers and phase shifting transformers.
6. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
7. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving Load radial
from a single source point.
8. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both sides of
the breaker.
9. An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Firm Transmission Service
following Contingency events. Curtailment of Firm Transmission Service is allowed both as a System adjustment (as identified in the column
entitled ‘Initial Condition’) and a corrective action when achieved through the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities, internal and external to the Transmission Planner’s planning region, remain within
applicable Facility Ratings and the re-dispatch does not result in any Non-Consequential Load Loss. Where limited options for re-dispatch
exist, sensitivities associated with the availability of those resources should be considered.
Page 27 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
10. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent pole
operated (IPO) or an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results in Delayed
Fault Clearing.
11. Excludes circuits that share a common structure (Planning event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event,
steady state 2b) for 1 mile or less.
12. An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following planning events.
In limited circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance
requirements are met. However, when Non-Consequential Load Loss is utilized under footnote 12 within the Near-Term Transmission
Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the Non-Consequential Load
Loss meets the conditions shown in Attachment 1. In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW
for US registered entities. The amount of planned Non-Consequential Load Loss for a non-US Registered Entity should be implemented in a
manner that is consistent with, or under the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
13. AppliesFor purposes of this standard, non-redundant components of a Protection System to the followingconsider are as follows:
a. A single protective relay which responds to electrical quantities, without an alternative (which may or may not respond to electrical
quantities) that provides comparable Normal Clearing times;
b. A single communications system associated with protective functions or types: pilot (#85), distance (#21), differential (#87), current (#50,
51,, necessary for correct operation of a communication-aided protection scheme required for Normal Clearing (an exception is a single
communications system that is both monitored and 67),reported at a Control Center);
c. A single station dc supply associated with protective functions required for Normal Clearing (an exception is a single station dc supply that
is both monitored and reported at a Control Center for both low voltage (#27 & 59), directional (#32, & 67), and tripping (#86, & 94).and
open circuit);
d. A single control circuitry (including auxiliary relays and lockout relays) associated with protective functions, from the dc supply through and
including the trip coil(s) of the circuit breakers or other interrupting devices, required for Normal Clearing (the trip coil may be excluded if
it is both monitored and reported at a Control Center).
Page 28 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Non-Consequential Load Loss under
footnote 12 is allowed as an element of a Corrective Action Plan in the Near-Term Transmission
Planning Horizon of the Planning Assessment, the Transmission Planner or Planning Coordinator
shall ensure that the utilization of footnote 12 is reviewed through an open and transparent
stakeholder process. The responsible entity can utilize an existing process or develop a new
process. .The process must include the following:
1. Meetings must be open to affected stakeholders including applicable regulatory
authorities or governing bodies responsible for retail electric service issues
2. Notice must be provided in advance of meetings to affected stakeholders including
applicable regulatory authorities or governing bodies responsible for retail electric
service issues and include an agenda with:
a. Date, time, and location for the meeting
b. Specific location(s) of the planned Non-Consequential Load Loss under footnote
12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed NonConsequential Load Loss under footnote 12 (as shown in Section II below) must be made
available to meeting participants
4. A procedure for stakeholders to submit written questions or concerns and to receive
written responses to the submitted questions and concerns
5. A dispute resolution process for any question or concern raised in #4 above that is not
resolved to the stakeholder’s satisfaction
An entity does not have to repeat the stakeholder process for a specific application of footnote
12 utilization with respect to subsequent Planning Assessments unless conditions spelled out in
Section II below have materially changed for that specific application.
II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Non-Consequential Load Loss under
footnote 12 which must include the following:
1. Conditions under which Non-Consequential Load Loss under footnote 12 would be
necessary:
a. System Load level and estimated annual hours of exposure at or above that Load
level
b. Applicable Contingencies and the Facilities outside their applicable rating due to
that Contingency
2. Amount of Non-Consequential Load Loss with:
Page 29 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
3.
4.
5.
6.
7.
8.
a. The estimated number and type of customers affected
b. An explanation of the effect of the use of Non-Consequential Load Loss under
footnote 12 on the health, safety, and welfare of the community
Estimated frequency of Non-Consequential Load Loss under footnote 12 based on
historical performance
Expected duration of Non-Consequential Load Loss under footnote 12 based on
historical performance
Future plans to alleviate the need for Non-Consequential Load Loss under footnote 12
Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 12
Alternatives to Non-Consequential Load Loss considered and the rationale for not
selecting those alternatives under footnote 12
Assessment of potential overlapping uses of footnote 12 including overlaps with
adjacent Transmission Planners and Planning Coordinators
III. Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is
Required
Before a Non-Consequential Load Loss under footnote 12 is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator must ensure that the applicable regulatory authorities or governing
bodies responsible for retail electric service issues do not object to the use of NonConsequential Load Loss under footnote 12 if either:
1. The voltage level of the Contingency is greater than 300 kV
a. If the Contingency analyzed involves BES Elements at multiple System voltage
levels, the lowest System voltage level of the element(s) removed for the
analyzed Contingency determines the stated performance criteria regarding
allowances for Non-Consequential Load Loss under footnote 12, or
b. For a non-generator step up transformer outage Contingency, the 300 kV limit
applies to the low-side winding (excluding tertiary windings). For a generator or
generator step up transformer outage Contingency, the 300 kV limit applies to
the BES connected voltage (high-side of the Generator Step Up transformer)
2. The planned Non-Consequential Load Loss under footnote 12 is greater than or equal to
25 MW
Once assurance has been received that the applicable regulatory authorities or governing
bodies responsible for retail electric service issues do not object to the use of NonConsequential Load Loss under footnote 12, the Planning Coordinator or Transmission Planner
must submit the information outlined in items II.1 through II.8 above to the ERO for a
determination of whether there are any Adverse Reliability Impacts caused by the request to
utilize footnote 12 for Non-Consequential Load Loss.
Page 30 of 31
TPL-001-45 — Transmission System Planning Performance Requirements
C.
Measures
M1. Each Transmission Planner and Planning Coordinator shall provide evidence, in
electronic or hard copy format, that it is maintaining System models within their
respective area, using data consistent with MOD-010 and MOD-012, including items
represented in the Corrective Action Plan, representing projected System conditions,
and that the models represent the required information in accordance with
Requirement R1.
M2.M1.
Each Transmission Planner and Planning Coordinator shall provide
dated evidence, such as electronic or hard copies of its annual Planning Assessment,
that it has prepared an annual Planning Assessment of its portion of the BES in
accordance with Requirement R2.
M3.M1.
Each Transmission Planner and Planning Coordinator shall provide
dated evidence, such as electronic or hard copies of the studies utilized in preparing
the Planning Assessment, in accordance with Requirement R3.
M4.M1.
Each Transmission Planner and Planning Coordinator shall provide
dated evidence, such as electronic or hard copies of the studies utilized in preparing
the Planning Assessment in accordance with Requirement R4.
M5.M1.
Each Transmission Planner and Planning Coordinator shall provide
dated evidence such as electronic or hard copies of the documentation specifying the
criteria for acceptable System steady state voltage limits, post-Contingency voltage
deviations, and the transient voltage response for its System in accordance with
Requirement R5.
M6. Each Transmission Planner and Planning Coordinator shall provide dated evidence,
such as electronic or hard copies of documentation specifying the criteria or
methodology used in the analysis to identify System instability for conditions such as
Cascading, voltage instability, or uncontrolled islanding that was utilized in preparing
the Planning Assessment in accordance with Requirement R6.
M7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall
provide dated documentation on roles and responsibilities, such as meeting minutes,
agreements, and e-mail correspondence that identifies that agreement has been
reached on individual and joint responsibilities for performing the required studies
and Assessments in accordance with Requirement R7.
Each Planning Coordinator and Transmission Planner shall provide evidence, such as email
notices, documentation of updated web pages, postal receipts showing recipient and date; or a
demonstration of a public posting, that it has distributed its Planning Assessment results to
adjacent Planning Coordinators and adjacent Transmission Planners within 90 days of having
completed its Planning Assessment, and to any functional entity who has indicated a reliability
need within 30 days of a written request and that the Planning Coordinator or Transmission
Planner has provided a documented response to comments received on Planning Assessment
results within 90 calendar days of receipt of those comments in accordance with Requirement
R8.
Page 31 of 31
| File Type | application/pdf |
| Author | Courtney Baughan |
| File Modified | 2019-07-31 |
| File Created | 2018-11-27 |