Great
River
Energy
1.0
Transmission
Department
Transmission
Planning
Issue Date:
January 30, 2015
Previous Date:
February 21, 2014
Planning
Criteria
SCOPE/PURPOSE
This document contains the planning criteria that Great River Energy (GRE) uses to ensure
that the GRE transmission system is adequate to reliably deliver power to systems connected
to and customers dependent upon GRE’s transmission system, provide support to distribution
systems interconnected to GRE’s transmission system, deliver energy from existing and new
generation facilities connected to the GRE transmission system and support effective
competition in energy markets. This document may be revised from time to time, as
appropriate, in response to new system conditions, new technologies being employed and
new operating procedures.
The criteria described below will be subject to change at any time at GRE’s discretion.
Situations that could precipitate such a change could include, but are not limited to, new
system conditions, extraordinary events, safety issues, operational issues, maintenance issues,
customer requests, Midcontinent Independent Transmission System Operator (MISO),
regulatory requirements and Regional Reliability Organizations (RROs), e.g. Midwest
Reliability Organization (MRO) or NERC requirements.
New interconnections to the GRE transmission system will be analyzed 1 to determine
whether system performance is degraded to the point where it violates the planning criteria.
When GRE is required to model the facilities of foreign Transmission Owners to conduct an
assessment, GRE will adhere to the facility owner’s planning criteria requirements.
2.0
REQUIREMENTS IN NERC STANDARDS
The transmission system will be evaluated for compliance with the requirements in NERC
Standards 2 TPL-001 through TPL-004 (Categories A to D) and TPL-001-4 3 (Categories P0
to P7) when it becomes fully effective (January 1, 2016). Both GRE-owned facilities and
facilities in foreign areas where GRE customer load may be impacted will be evaluated.
3.0
SYSTEM MODELING CRITERIA
Steady state and transient assessments are performed to assure avoidance of equipment
overloads, prevention of unacceptable system voltage levels and satisfactory system reactive
power resources. Assessments will include consideration of the following system load
conditions for possible further analysis. Detailed analysis will be conducted on those system
conditions which are likely to cause the most severe impact to criteria.
1
Per GRE TDOG-108, “GRE Planning Criteria”
NERC Standards can be found at:
http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RS CompleteSet.pdf
3
Table 1 from NERC Standard TPL-001-4 is included as Appendix I
2
1)
2)
3)
4)
5)
6)
Summer peak
Winter peak
Summer off-peak
Spring peak
Fall peak
Minimum load
For generator interconnection studies, new generation will be studied with the new
generation and all other local generation at full output, at both minimum load and peak load
conditions, to determine whether the aggregate of the generation in the local area can be
delivered to the aggregate of load on the transmission system. 4
4.0
VOLTAGE CRITERIA
GRE’s planning criteria regarding voltage limits on equipment are shown in Table 1.
Table 1
GRE Voltage Criteria
Voltage Ranges
Facility
Hubbard 230 &
115 kV
Wing Rive r 230 &
115 kV
4
5
6
7
Allowable Planned Voltage Tolerances
Per Unit of Nominal
Normal
Emergency
Transient
Max
Min
Max
Min
Max
Min
1.05
0.96
1.10
0.92
1.20
0.75
1.05
0.96
1.10
0.92
1.20
0.75
Ramsey 230 kV
1.05
0.95
1.15
0.90
Balta 230 kV
1.05
0.95
1.10
0.90
Coal Creek 230 kV7
Dickinson 345 kV
Fond du Lac 69 kV
Load Serving Buses
Remaining Buses
Voltage Flicker (%)
1.05
1.05
1.10
1.05
1.05
3%
0.95
0.95
0.95
0.95
0.95
NA
1.10
1.10
1.10
1.10
1.10
5%
0.90
0.90
0.9
0.92
0.90
NA
MISO Tariff, Attachment X, section 3.2.2. 2, effective November 14, 2014.
The Ramsey bus is allowed 1.65 per unit for 5 cycles.
The Balta bus is allowed 1. 65 per unit for 5 cycles.
This bus has a 1.20 p.u. overvoltage criteria for CU DC Bi-pole fault (ei2).
Page 2 of 10
1.30 for
200 msec5
1.30 for
200 msec6
1.18
1.17
1.20
1.20
1.20
NA
0.70
0.70
0.70
0.70
0.70
0.70
0.70
NA
5.0
FACILITY LOADING CRITERIA
GRE’s planning criteria for loading of transmission facilities are shown in Table 2.
Table 2
GRE Facility Loading Criteria
Facility
Ratings
Condition
Normal
Emergency 8
6.0
Station
Transforme r
Equipment
Loadin
Loading Duration
Duration Loading Duration
g
100% Continuous 100% Continuous 100% Continuous
100%
NA
100%
NA
100%
NA
Line
MW-MILE CRITERIA
6.1 Radial MW-Mile Analysis
•
The MW- mile value for a radially fed circuit is calculated by summing the flow
across each radial line segment times the length (in miles) of the respective
segment.
•
The MW- mile value of the circuit should not exceed 100 MW- miles.
6.2 Breaker MW-Mile Analysis
•
The Breaker MW-Mile calculation is based on the product of the total real power
components (load and generation) on the line(s) between the circuit breakers and
the total line mileage of the same line(s) between the same circuit breakers.
•
MW-mile magnitudes of less than 1000 are typical and acceptable.
•
MW-mile magnitudes between 1000 and 2000 are higher than usual. If records
indicate poor reliability, then corrective action shall be investigated.
•
MW-mile magnitudes higher than 2000 indicate a high amount of exposure and
risk to the system. Corrective action shall be investigated.
8
GRE will conduct an engineering analysis, when needed, to determine whether a specific facility is capable a
short-term emergency rating for a limited time duration.
Page 3 of 10
7.0
MAXIMUM OF THREE SOURCE TERMINALS
GRE will not allow breaker exposure to exceed three sources (terminals). Transmission
installations that exceed a three-terminal level will require the installation of either a normal
open point between the group of breakers or a breaker station, such that at least one breaker
terminal is eliminated from the exposure.
New three-terminal exposures will be reviewed to determine whether appropriate relay
protection can exist in the new, proposed configuration. Resolution to potential relaying
concerns can be accomplished by adding breaker protection or by opening the system.
GRE will not allow its system to be opened until the new configuration had been thoroughly
analyzed for impacts to service to customers.
8.0
TRANSMISSION SYSTEM PLANNING PERFORMANCE REQUIREMENTS
8.1. Steady State Assessments
GRE will maintain appropriate planning criteria for all categories of events allowing for
some loss in demand for some Category P2 events. Please reference NERC Standard
TPL-001-4, Table 1 for a further description of the performance requirements for the
various event categories.
In addition, generation interconnection analysis will include the loss of a large, local
load that might affect the loading on the local transmission system.
8.2. Transient Stability Assessments
Transient and dynamic stability assessments are generally performed to assure the
avoidance of loss of generator synchronism, prevention of system voltage collapse and
the adequacy of system reactive power resources during the 20 seconds following a
system disturbance. The transient and dynamic system stability performance criteria to
be utilized by GRE shall include the following factors.
GRE will perform transient stability assessments when a need is indicated or on a
regular basis per NERC Standards. These assessments will include, but are not limited
to, consideration of the following system load conditions:
1)
2)
3)
4)
Summer peak
Summer off-peak
Winter peak
Minimum load
The first and third conditions are typically used for voltage stability studies. The second
and fourth conditions are primarily used for angular stability studies.
GRE will perform local and regional disturbances for assessment purposes on Category
P1 through P7 events. All disturbances will be given a one (1) cycle margin on breaker
clearing time.
Page 4 of 10
The performance assessment will be based on:
a. Voltage stability based on meeting GRE transient criteria or the criteria of the
facility owner.
b. Voltage stability will be maintained by operating at or below the Plimit defined
as the power transfer limit across the critical interface. Plimit will be 90 percent
of the Pcritical where Pcritical is defined as the maximum power transfer (the
nose of P-V curve).
c. Angular stability will avoid separation of the system unless some generation
units are deliberately islanded.
d. Cascade tripping of transmission lines will be monitored and avoided unless
planned cascading is initiated.
e. Uncontrolled loss of load will be avoided.
f. No unit will exhibit poorly damped angular oscillations or unacceptable power
swings. All machine rotor angle oscillations will be positively damped and
calculated from the Successive Positive Peak Ratio (SPPR) of the peak-topeak amplitude of the rotor oscillation. SPPR and the associated Damping
Factor will be calculated as:
SPPR = Successive swing amplitude / Previous swing amplitude and,
Damping Factor = (1 - SPPR) * 100 (in %)
The damping criteria are as follows (with increased damping required for
higher probability events):
For disturbances (with faults): SPPR (maximum) = 0.95; Damping Factor
(minimum) = 5%
For line trips: SPPR (maximum) = 0.90; Damping Factor (minimum) = 10%
The calculation of damping is based on successive positive peak ratios. In
some cases, the SPPR calculation fails due to a constant rate of change of
rotor angles caused by a significant generation loss and resulting significant
frequency change. In these cases, Prony analysis should be utilized to
calculate damping ratios on the appropriate modes of oscillation, and the
damping ratio criteria (equivalent to the damping factor criteria above) are as
follows:
•
•
For disturbances (with faults): Minimum Damping Ratio = 0.0081633
For line trips: Minimum Equivalent Damping Ratio = 0.016766
Page 5 of 10
8.3. Voltage Flicker
Voltage fluctuations may be noticeable as visual lighting variations (flicker) and can
damage or disrupt the operation of electronic equipment. Sources of flicker are not
allowed to produce flicker to adjacent customers that exceeds the GRE guideline shown
below (Figure 1). The source will be responsible and liable for corrections if the
interconnecting Facility is the cause of objectionable flicker levels.
The flicker limits defined below are applicable to all interconnections made to the GRE
system. The criteria for acceptable voltage flicker levels are defined by the
requirements of regulatory entities in the states in which GRE owns and operates
transmission facilities, IEEE recommended practices and requirements and the
judgment of GRE.
The following flicker level criteria are to be modeled at periods that the element
causing the flicker is expected to be integrated into or removed from the transmission
grid. If electrically close, generation should be scheduled off- line if not a baseload
plant. GRE requires studies to be done for normal conditions and with an outage.
If the limits defined below are exceeded under intact or outage conditions, the flicker
producing source must be operated in a manner that does not adversely affect other
loads. Planned outages can be dealt with by coordinating transmission and flicker
producing load outages. Because operating restrictions during unplanned outages may
be severe, it would be prudent for the owner of the harmonic producing load to study
the effect of known, critical or long-term outages before they occur so that remedial
actions or operating restrictions can be designed before an outage occurs.
All GRE buses are required to adhere to the following two criteria.
1) Relative steady state voltage change is limited to 3 percent of the nominal
voltage for intact system condition simulations. The relative steady state
voltage change is the difference in voltage before and after an event, such as
capacitor switching or large motor starting.
2) Relative steady state voltage change is limited to 5 percent of the nominal
voltage for contingency condition simulations.
GRE uses the flicker curve in IEEE Standard 141-1993 (commonly referred to as “The
Modified GE Flicker Curve”) to determine the acceptability of single frequency flicker.
Page 6 of 10
Figure 1
GRE Voltage Flicker Guideline
GRE GUIDELINE
8.4
Harmonic voltage distortion
GRE advises the interconnection customer to account for harmonics during the early
planning and design stages. The interconnection customer’s equipment shall not
introduce excessive distortion to the transmission system voltage and current
waveforms per IEEE 519-1992. Refer to Tables 3 and 4 below for voltage distortion
limits.
Table 3
Voltage Distortion Limits
Individual Voltage
Distortion IHD %
Total Voltage
Distortion THD
Below 69 kV
3.0
5.0
69 kV to 115 kV
1.5
2.5
115 kV and above
1.0
1.5
Bus Voltage At PCC
Source: IEEE 519, Table 11.1
Page 7 of 10
Table 4
Curre nt Distortion Limits For Non-Linear Loads
At The Point Of Common Coupling
(PCC) From 120 To 69,000 Volts
Maximum Harmonic Current Distribution in % of Fundame ntal
Harmonic Order (Odd Harmonics)
I(sc)/I(l)
<11
11<h<17
17<h<23
23<h<35
35<h
THD
20
4.0
2.0
1.5
0.6
0.3
5.0
20-50
7.0
3.5
2.5
1.0
0.5
8.0
50-100
10.0
4.5
4.0
1.5
0.7
12.0
100-1000
12.0
5.5
5.0
2.0
1.0
15.0
1000
Where:
15.0
7.0
6.0
2.5
1.4
20.0
I(sc) = Maximum short circuit current at PCC
I(l) = Maximum load current (fundamental frequency) at PCC
PCC = Point of Common Coupling between Applicant and utility
Generation equipment is subject to the lowest I(sc)/I(l) values
Even harmonics are limited to 25% of odd harmonic limits given above
Source: IEEE 519, Table 10.3
A special study will be required for situations when the fault to load ratio is less than 10.
9.0
SPECIAL PROTECTION SYSTEMS
GRE will not permit the addition of new Special Protection Systems (SPSs) with the
following exceptions.
Temporary
GRE will only consider any new SPS to be temporary and valid for a maximum of five
(5) years to allow for planned transmission upgrades to be completed while serving new
load or generation. The transmission resolution will need to be placed into the MISO
Transmission Expansion Plan (MTEP) process and scope and schedule will need to be
approved by GRE prior to the installation and granting of the SPS. An extension of the
SPS will not occur unless transmission cascading events, system collapse or large loss of
Page 8 of 10
load are an issue. Any cost of extending the SPS will be borne by the requesting party
including any cost for documentation requirements to the Reliability Organization,
Planning Authority or Reliability Coordinator.
Legacy SPSs
A legacy SPS may be maintained if there is significant reliability benefit such as
preventing cascading events, system collapse or large loss of load.
All SPSs must meet all the criteria and guidelines of a NERC and Regional Entity defined
SPS including dual redundancy of all components of the SPS and the ability to stay within all
applicable reliability criteria with the failure of a component of the SPS. Testing of the SPS
and documentation of the testing is also required.
10.0
REFERENCES
1.
GRE TDOG-108, Transmission Planning Study Proc edures
2.
Nort h America Electric Reliability Corporation, http://www.nerc.com/pa/Stand/Pages/default.aspx
3.
NERC Reliability Standards Complete Set:
http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RS CompleteSet.pd
f
4.
IEEE Standard 141-1993, “IEEE Recommended Guide for Electric Power Distribution for
Industrial Plants”
5.
IEEE Standard 519-1992, “IEEE Recommended Practices and requirements for Harmonic
Cont rol in Electric Power Systems”
Page 9 of 10
Appendix I
NERC TPL-001-4, Table 1
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
Initial Condition
Normal System
P1
Single
Contingency
Normal System
Event
1
Fault Type
None
N/A
Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
3Ø
5. Single Pole of a DC line
1.
2.
P2
Single
Contingency
Interruption of Firm
Transmission
4
Service Allowed
Non-Consequential
Load Loss Allowed
EHV, HV
No
No
EHV, HV
No
9
No
12
EHV, HV
No
9
No
12
EHV
No
9
HV
Yes
BES Level
3
SLG
Opening of a line section w/o a fault
7
N/A
Bus Section Fault
No
SLG
Normal System
3. Internal Breaker Fault
(non-Bus-tie Breaker)
2
8
4. Internal Breaker Fault (Bus-tie Breaker)
Yes
EHV
No
9
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
9
adjustments
Event
1
Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
5. Single pole of a DC line
P4
Multiple
Contingency
(Fault plus stuck
10
breaker )
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)
P6
Multiple
Contingency
(Two
overlapping
singles)
Normal System
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
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line
Fault Type
3Ø
2
BES Level
3
Interruption of Firm
Transmission
4
Service Allowed
Non-Consequential
Load Loss Allowed
EHV, HV
No
9
EHV
No
9
HV
Yes
Yes
EHV, HV
Yes
Yes
EHV
No
HV
Yes
Yes
EHV, HV
Yes
Yes
EHV, HV
Yes
Yes
No
12
SLG
No
SLG
SLG
9
No
SLG
3Ø
SLG
9
Standard TPL-001-4 — Transmission System Planning Performance Requirements
Category
Initial Condition
P7
Multiple
Contingency
(Common
Structure)
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
SLG
2
BES Level
EHV, HV
3
Interruption of Firm
Transmission
4
Service Allowed
Non-Consequential
Load Loss Allowed
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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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