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pdfStandard TPL-001-4 — Transmission System Planning Performance Requirements
A. Introduction
1.
Title:
Transmission System Planning Performance Requirements
2.
Number:
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:
TPL-001-4
4.1. Functional Entity
5.
4.1.1.
Planning Coordinator.
4.1.2.
Transmission Planner.
Effective Date: 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)
P2-3 (above 300 kV)
P3-1 through P3-5
P4-1 through P4-5 (above 300 kV)
P5 (above 300 kV)
1
Standard TPL-001-4 — Transmission System Planning Performance Requirements
B. Requirements
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 standards, 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: Medium]
[Time Horizon: Long-term Planning]
1.1.
R2.
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.
New planned Facilities and changes to existing Facilities
1.1.4.
Real and reactive Load forecasts
1.1.5.
Known commitments for Firm Transmission Service and Interchange
1.1.6.
Resources (supply or demand side) required for Load
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 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.
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 :
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.
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Standard TPL-001-4 — Transmission System Planning Performance Requirements
2.1.5.
2.2.
Controllable Loads and Demand Side Management.
Duration or timing of known Transmission outages.
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 studied. The studies 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:
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.
3
Standard TPL-001-4 — Transmission System Planning Performance Requirements
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:
2.7.
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.
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 Systems
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.
Use of rate applications, DSM, new technologies, or other initiatives.
2.7.2.
Include actions to resolve performance deficiencies identified in multiple
sensitivity studies or provide a rationale for why actions were not necessary.
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
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Standard TPL-001-4 — Transmission System Planning Performance Requirements
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.
R3.
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.
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.
3.3.
Contingency analyses for Requirement R3, Parts 3.1 & 3.2 shall:
3.3.1.
3.3.2.
3.4.
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:
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
5
Standard TPL-001-4 — Transmission System Planning Performance Requirements
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.
R4.
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.
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: Longterm Planning]
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 Special Protection System 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.
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.
4.3.1.2.
Successful high speed (less than one second) reclosing and
unsuccessful high speed reclosing into a Fault where high speed
reclosing is utilized.
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.
6
Standard TPL-001-4 — Transmission System Planning Performance Requirements
4.3.1.3.
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.
4.5.
Tripping of Transmission lines and transformers where transient
swings cause Protection System operation based on generic or
actual relay models.
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.
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.
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]
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]
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]
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.
7
Standard TPL-001-4 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a.
b.
c.
d.
The System shall remain stable. Cascading and uncontrolled islanding shall not occur.
Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event.
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.
g.
h.
i.
Applicable Facility Ratings shall not be exceeded.
System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as established by the Planning Coordinator and the Transmission
Planner.
Planning event P0 is applicable to steady state only.
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.
Category
P0
No Contingency
P1
Single
Contingency
Fault Type 2
BES Level 3
Interruption of Firm
Transmission
Service Allowed 4
Non-Consequential
Load Loss Allowed
None
N/A
EHV, HV
No
No
Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
3Ø
EHV, HV
No9
No12
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
Event 1
Initial Condition
Normal System
Normal System
5. Single Pole of a DC line
1.
P2
Single
Contingency
2.
SLG
Opening of a line section w/o a fault
7
N/A
Bus Section Fault
SLG
Normal System
3. Internal Breaker Fault
(non-Bus-tie Breaker)
8
4. Internal Breaker Fault (Bus-tie Breaker)
EHV
9
No
No
HV
Yes
Yes
EHV, HV
Yes
Yes
SLG
8
SLG
8
Standard TPL-001-4 — Transmission System Planning Performance Requirements
Category
P3
Multiple
Contingency
Initial Condition
Loss of generator unit
followed by System
adjustments9
Event
1
Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
4. Shunt Device 6
5. Single pole of a DC line
P4
Multiple
Contingency
(Fault plus stuck
breaker10)
Normal System
Loss of multiple elements caused by a stuck
10
breaker (non-Bus-tie Breaker) attempting to
clear a Fault on one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
5. Bus Section
6. Loss of multiple elements caused by a
10
stuck breaker (Bus-tie Breaker)
attempting to clear a Fault on the
associated bus
P5
Multiple
Contingency
(Fault plus relay
failure to
operate)
Normal System
P6
Multiple
Contingency
(Two
overlapping
singles)
Loss of one of the
following followed by
9
System adjustments.
1. Transmission Circuit
5
2. Transformer
6
3. Shunt Device
4. Single pole of a DC line
Delayed Fault Clearing due to the failure of a
non-redundant relay13 protecting the Faulted
element to operate as designed, for one of
the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
5. Bus Section
Loss of one of the following:
1. Transmission Circuit
5
2. Transformer
3. Shunt Device 6
4. Single pole of a DC line
Fault Type 2
BES Level 3
Interruption of Firm
Transmission
Service Allowed 4
Non-Consequential
Load Loss Allowed
3Ø
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
EHV, HV
Yes
Yes
EHV
No
No
HV
Yes
Yes
EHV, HV
Yes
Yes
EHV, HV
Yes
Yes
SLG
SLG
SLG
9
SLG
3Ø
SLG
9
Standard TPL-001-4 — 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
11
structure
2. Loss of a bipolar DC line
Fault Type 2
BES Level 3
Interruption of Firm
Transmission
Service Allowed 4
Non-Consequential
Load Loss Allowed
SLG
EHV, HV
Yes
Yes
10
Standard TPL-001-4 — 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-of-Way11.
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.
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.
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 internal breaker fault.
f. Other events based upon operating experience, such as
consideration of initiating events that experience suggests may
result in wide area disturbances
11
Standard TPL-001-4 — 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 Non-Consequential 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 re-dispatch, 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 NonConsequential Load Loss. Where limited options for re-dispatch exist, sensitivities associated with the availability of those resources should be considered.
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 NonConsequential 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. Applies to the following relay functions or types: pilot (#85), distance (#21), differential (#87), current (#50, 51, and 67), voltage (#27 & 59), directional (#32, &
12
Standard TPL-001-4 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
67), and tripping (#86, & 94).
13
Standard TPL-001-4 — 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:
a. The estimated number and type of customers affected
Standard TPL-001-4 — Transmission System Planning Performance Requirements
3.
4.
5.
6.
7.
8.
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 Non-Consequential 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 Non-Consequential 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 NonConsequential Load Loss.
Standard TPL-001-4 — 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. 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. 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. 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. 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.
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.
D. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
Regional Entity
1.2 Compliance Monitoring Period and Reset Timeframe
Not applicable.
Standard TPL-001-4 — Transmission System Planning Performance Requirements
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4 Data Retention
The Transmission Planner and Planning Coordinator shall each retain data or evidence to
show compliance as identified unless directed by its Compliance Enforcement Authority
to retain specific evidence for a longer period of time as part of an investigation:
The models utilized in the current in-force Planning Assessment and one
previous Planning Assessment in accordance with Requirement R1 and Measure
M1.
The Planning Assessments performed since the last compliance audit in
accordance with Requirement R2 and Measure M2.
The studies performed in support of its Planning Assessments since the last
compliance audit in accordance with Requirement R3 and Measure M3.
The studies performed in support of its Planning Assessments since the last
compliance audit in accordance with Requirement R4 and Measure M4.
The documentation specifying the criteria for acceptable System steady state
voltage limits, post-Contingency voltage deviations, and transient voltage
response since the last compliance audit in accordance with Requirement R5 and
Measure M5.
The documentation specifying the criteria or methodology utilized in the analysis
to identify System instability for conditions such as Cascading, voltage
instability, or uncontrolled islanding in support of its Planning Assessments since
the last compliance audit in accordance with Requirement R6 and Measure M6.
The current, in force documentation for the agreement(s) on roles and
responsibilities, as well as documentation for the agreements in force since the
last compliance audit, in accordance with Requirement R7 and Measure M7.
The Planning Coordinator shall retain data or evidence to show compliance as identified
unless directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation:
Three calendar years of the notifications employed in accordance with
Requirement R8 and Measure M8.
If a Transmission Planner or Planning Coordinator is found non-compliant, it shall keep
information related to the non-compliance until found compliant or the time periods
specified above, whichever is longer.
1.5 Additional Compliance Information
None
Standard TPL-001-4 — Transmission System Planning Performance Requirements
2. Violation Severity Levels
R1
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 1.1.6.
The responsible entity’s System
model failed to represent two of the
Requirement R1, Parts 1.1.1 through
1.1.6.
The responsible entity’s System
model failed to represent three of the
Requirement R1, Parts 1.1.1 through
1.1.6.
Severe VSL
The responsible entity’s System model
failed to represent four or more of the
Requirement R1, Parts 1.1.1 through
1.1.6.
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-012 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.
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
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
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.
18
Standard TPL-001-4 — Transmission System Planning Performance Requirements
Lower VSL
Moderate VSL
High VSL
Severe VSL
OR
Table 1.
OR
The responsible entity did not perform
studies as specified in Requirement
R3, Part 3.2 to assess the impact of
extreme events.
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.
The responsible entity did not
perform Contingency analysis as
described in Requirement R3, Part
3.3.
OR
The responsible entity did not base its
studies on computer simulation models
using data provided in Requirement R1.
R4
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
R4, Part 4.1 to determine that the
BES meets the performance
requirements for one of the categories
(P1 through P7) in Table 1.
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 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.
OR
The responsible entity did not
perform Contingency analysis as
described in Requirement R4, Part
4.3.
The responsible entity did not perform
studies as specified in Requirement R4,
Part 4.1 to determine that the BES
meets the performance requirements
for three or more of the categories (P1
through P7) in Table 1.
OR
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.
19
Standard TPL-001-4 — Transmission System Planning Performance Requirements
Lower VSL
Moderate VSL
High VSL
Severe VSL
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 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.
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.
20
Standard TPL-001-4 — Transmission System Planning Performance Requirements
E.
Regional Variances
None.
Version History
Version
Date
Action
Change Tracking
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 TPL-001-0
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 RM0616-009
Revised (Project 201011)
2
August 4, 2011
Revision of TPL-001-1; includes merging and
upgrading requirements of TPL-001-0, 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 TPL-001-1, TPL002-1b, TPL-003-1a, and TPL-004-1. 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.
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.
| File Type | application/pdf |
| File Title | Microsoft Word - TPL-001-4.docx |
| Author | bensonm |
| File Modified | 2018-11-06 |
| File Created | 2013-02-14 |