Executive Summary:

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 01 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 01 projects.

This analysis is effectively a screening study to determine whether the addition of the cluster 01 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 01 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 01 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 140 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
5. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

In the original 2027SP base case, it was found that the system becomes unstable for contingencies P1.13, P4.24, P4.29, P5.06, P5.08 and P7.03 since the units in the City of Rochelle and Mendota areas are connected to the bulk power system just through a single branch, McGirr – Dixon, during post-fault configuration. As such, it appears that local voltage collapse occurs in the weak network conditions during post-fault period. Plots from the dynamic simulations for these simulations are provided in Attachment 4.

To mitigate the instability issue, ESS H440 generating unit was turned off, and LEED (Q57), Mendota Hills (AD1-067) and AD1-013 generating units were dispatched at a reduced capacity in “Alternate Base Case” folder to satisfy the Short Term Emergency (STE) ratings of Haumesser – W. Dekalb 138 kV and McGirr Rd – Dixon 138 kV circuits, and thus secure the case for N-0 and N-1 conditions for unstable contingencies.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 01 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 01 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

Cluster 01 projects meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCAU model of AE2-341 GEN, AF1-030 GEN, AG1-118 GEN1, AG1-118 GEN2 and AG1-127 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

Fictitious frequency response at AE2-341 generator bus tripped the queue project due to the action of instantaneous under frequency relays when faults were applied to AF1-030/AE2-341 POI. This issue is mitigated by increasing the relay pickup time for frequency relay instance 94312513 to 20 seconds to avoid fictitious frequency tripping of the unit.

Fictitious frequency response at the AF1-030 generator bus tripped the queue project due to the action of instantaneous over frequency and under frequency relays when faults were applied to AF1-030/AE2-341 POI. This issue is mitigated by increasing the relay pickup time for frequency relay instances 94359509 and 94359511 to 20 seconds to avoid fictitious frequency tripping of the units.

AF1-030 unit tripped due to an overvoltage spike following fault clearing. This was mitigated by adding a small pick-up time of 0.113 seconds to the relay instance 94359501 to resolve the overvoltage tripping.

The AC1-110 unit tripped by angle deviation relays for 3 contingencies (P4.48.3B3, P4.50.3B3 and P4.52.3B3). The AC1-111 unit tripped by angle deviation relays for 4 contingencies (P4.39.3B3, P4.44.3B3, P4.45.3B3 and P4.46.3B3). These tripping events were observed in previous stability analysis studies for AC1-109/110/111 and AF2-363/366 and therefore are not attributed to Cluster 01 stability analysis.

The DVR (Dynamic Voltage Recovery) criteria have been violated under several contingencies due to instability and unit tripping, particularly at the Mendota location, as observed in events P1.13, P4.24, P4.29, P5.06, P5.08, and P7.03. These contingencies have been simulated with reduced dispatch for several units and no DVR violation has been observed. Additional DVR violations occurred under contingencies P4.48.3B3, P4.50.3B3, and P4.52.3B3, where the tripping of the AC1-110 unit led to angle deviations. Notably, DVR violations identified at the AC1-110 generator bus terminals during contingencies P4.42.3B3 and P4.43.3B3 were not mitigated, as generation buses and points-of-interconnection (Aurora) are not valid monitoring points for assessing DVR compliance. Similarly, violations at the Aurora and Batavia buses (P4.42.3B3 and P4.53.3B3) were not addressed, given that the DVR recovery envelope was breached at only two buses per contingency—below the threshold of ten or more applicable buses required for mitigation to be considered.

No mitigations were found to be required.

Table 1: TC1 Cluster 01 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 02 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 02 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 02 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 02 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 02 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 45 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
5. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies were identified for this study.

There are no three-phase faults single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic).

There are no three-phase faults with three-phase delayed clearing due to a stuck breaker (GO Breakers with A-contact Logic).

There are no three-phase faults with single-phase delayed clearing due to a stuck breaker (GO Breakers with FD Logic).

Stations at which the faults listed above will be applied are:

• AE1-114 POI 138 kV
• Lancaster TSS 119 138 kV
• Lena TSS 180 138 kV
• Maryland TSS 124 138 kV

The SPOG 2-51 (TSS 119 Lancaster automatic line 11904 trip schemes prevent islanding of TSS 969 Ecogrove Generation). The following assumptions were made for contingency development:

1. TSS 969 Ecogrove Generation will be tripped when one of the following conditions are met:

1. 138 kV line 11904 circuit breaker is open at TSS 119 Lancaster; or,
2. 138 kV line 17121 circuit breaker is open AND either 138 kV bus tie 5-7 OR 6-7 is open at TSS 119 Lancaster.

For all simulations, the queue projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 02 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 02 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AE1-114 meets the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA model of AE1-114 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away of Cluster 02. The CSCR results are summarized in Table 4 through Table 9 and revealed a minimum CSCR value of 3.01 for P4.18, P4.15, P4.16 and so on and a maximum CSCR value of 4.444 for P1.08, P1.06, P0.01.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 3 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 3 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 3 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 3 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 3 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 166 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 3 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 3 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 3 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-350 meets the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 model of AF2-350 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system these plots are ignored.

No mitigations were found to be required.

Table 1: TC1 Cluster 3 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 4 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 4 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 4 projects will meet the dynamics requirements of the NERC, ComEd, and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 4 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 4 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 168 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase to ground faults with single-phase delayed clearing due to a stuck breaker (IPO breakers)
6. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
7. Three-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 4 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 4 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 4 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AE2-321 meets the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 model of AE2-321 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this response has no effect on the system.

AE2-321 exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. This issue did not cause instability in the system. However, to reduce the reactive power settling time and eliminate the potential for the plant’s voltage controller to interact with other voltage controlling equipment in the AC system, a 5% reactive power droop was introduced to the AE2-321 plant controller.

Initial simulations showed poorly damped oscillations in AC1-111 power. The AC1-111 dynamic model was updated to the most recent (revision 1) model which uses the AC7B exciter model instead of the ESAC1A model. The updated dynamic model eliminated these oscillations.

No mitigations were found to be required.

Table 1: TC1 Cluster 4 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 5 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 5 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 5 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 5 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 5 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 107 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase to ground faults with single-phase delayed clearing due to a stuck breaker (IPO breakers)
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 5 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 5 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 5 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-226 and AF2-319 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 models of AF2-226 GEN and AF2-319 GEN showed erratic behavior for some contingencies in which this generator has been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

Initial simulations showed AF2-226 and AF2-319 exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. The reactive power settling time was decreased by adjusting the PPC Q/V controller PI gains for both projects (Kp = 1 from 0, Ki = 5 from 0.5). The developer confirmed that the updated controller parameters are acceptable.

Simulations showed AF2-142, AF2-143, and AE1-163 getting stuck in high voltage ride through (HVRT) mode for extended periods after fault clearance for several contingencies. This resulted in a 345 kV POI voltage of about 1.1 pu for more than 5 seconds. For AF2-142 and AF2-143, this was resolved by adjusting the HVRT threshold and deadband to 1.15 pu (from 1.1 pu) and 0.15 pu (from 0.1 pu), respectively. These parameter adjustments were confirmed by the respective project developers. For AE1-163, the dynamic model was updated to the Vestas UDM which was submitted for the AE1-163/AE2-281 necessary study as per the developer’s request.

Initial simulations showed poorly damped oscillations in AC1-111 power. The AC1-111 dynamic model was updated to the most recent (revision 1) model which uses the AC7B exciter model instead of the ESAC1A model. Revision 1 of the AC1-111 dynamic model was used in the last iteration of the AC1-111 dynamic analysis, therefore it is assumed that the AC7B model is accurate relative to what is in the field. The updated dynamic model eliminated these oscillations.

No mitigations were found to be required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 6 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 6 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 6 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 6 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 6 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 103 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase to ground faults with single-phase delayed clearing due to a stuck breaker (IPO breakers)
6. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
7. Three-phase faults with loss of multiple-circuit tower line;

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 6 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 6 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 6 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-392 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 models of AF2-392 showed erratic behavior for some contingencies in which this generator has been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

AF2-392 exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. This issue did not cause instability in the system.

Voltage response at O29GEN1 (Bus 276157) and O29GEN2 (Bus 276158) terminal bus tripped the generators due to the action of under voltage relays when faults were applied at Hoyle Road 138 kV (AF2-392 POI) and Nelson 138 kV. The relay pickup times for voltage relay instances 27615701 (O29GEN1, 0.45 pu, 0.26 sec), 27615702 (O29GEN1, 0.45 pu, 0.3 sec), 27615703 (O29GEN1, 0.65 pu, 0.3 sec), 27615801 (O29GEN2, 0.45 pu, 0.26 sec), 27615802 (O29GEN2, 0.45 pu, 0.3 sec) and 27615803 (O29GEN2, 0.65 pu, 0.3 sec) were set to a duration shorter than the fault duration of 20 cycles. Therefore, the relay pickup times for voltage relays were extended to 0.36667 seconds, to avoid tripping during the fault.

Voltage response at BROOKE Wind generator terminal bus (Bus 631215) tripped the generator due to the action of instantaneous voltage relay 63121502 (0.892 pu, 0.0 sec) when faults were applied at Nelson 345 kV. Therefore, the relay pickup times for frequency relay instance 63121502 was updated to 0.36667 seconds, to avoid tripping during the fault.

No mitigations were found to be required.

Table 1: TC1 Cluster 6 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 07 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 07 projects.

This analysis is effectively a screening study to determine whether the addition of the cluster 07 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 07 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 07 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 110 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run).
2. Three-phase faults with normal clearing time.
3. Single-phase faults with stuck breaker.
4. Three-phase faults single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic).
5. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO Breakers with A-contact Logic).
6. Three-phase faults with single-phase delayed clearing due to a stuck breaker (GO Breakers with FD Logic).

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all the fault contingencies tested on the 2027 peak load case:

1. Cluster 07 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 07 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AE2-261, AG1-236, and AG1-460 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCAU model of AE2-261, and AG1-236 showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

AG1-236 GEN exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. This issue did not cause instability in the system and the models have been tuned to achieve a faster reactive power output settlement by updating Kp and Kc from REPCTA1 module in generator AG1-236.

The tripping of AD2-100 was identified in contingencies P4.68, P4.69, and P4.70, as well as during the Cluster 07 pre-project test. Therefore, it has been confirmed that the tripping of AD2-100 is not caused by the TC1 Cluster 07 queue projects. Tripping was avoided for all events by updating the undervoltage protection settings: Relay 93677405 was adjusted to 0.177 seconds (10 cycles, adding one cycle to the original P4 fault clearing time of 9 cycles).

No mitigations were found to be required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 08 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 08 projects.

This analysis is effectively a screening study to determine whether the addition of the cluster 08 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 08 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 08 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 110 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase faults single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic);
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
5. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the ComEd 345 kV transmission system.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 08 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 08 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AE1-172, AE2-173, AE2-223, and AF2-225 meet the 0.95 leading and lagging PF requirement.

The AE1-205 unit tripped by undervoltage relays for 4 contingencies (P4.61, P4.62, P4.63, P4.64). Contingencies P4.61, P4.62, P4.63 and P4.64 involved a three-phase stuck breaker fault at Pontiac Midpoint 345 kV clearing in 13 cycles. As per NERC Standard PRC-024 requirements, these contingencies were found to meet the corresponding NERC PRC-024 LVRT criteria. A similar tripping issue was observed in AF2-252/AF2-352 dynamic study.

AF2-225 GEN exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. This issue did not cause instability in the system and the model is tuned by adjusting the Kc parameter in the plant controller (REPCA1) to 0.1 from 0 to achieve a faster reactive power output settlement. The change has been confirmed by the developer.

The IPCMD and IQCMD states in the REGCAU model of AE2-173 GEN, and AE2-223 GEN, and AF2-225 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

Fictitious post-fault overvoltage tripping at AF2-252 and AF2-352 generator buses tripped the queue projects due to the action of instantaneous over-voltage relays for contingencies P4.62 and P4.63. Therefore, the relay pickup times for voltage relay instances 96061504 and 95961504 were set to 0.0305 seconds from 0.001 to avoid fictitious voltage tripping of the units.

No mitigations were found to be required.

Table 1: TC1 Cluster 08 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 09 are listed in Table 1: TC1 Cluster 09 Projects below. This report will cover the dynamic analysis of Cluster 09 projects.

This analysis is effectively a screening study to determine whether the addition of the cluster 09 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 09 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 09 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 79 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run).
2. Three-phase faults with normal clearing time.
3. Three-phase bus faults with normal clearing time.
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic).
5. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure.
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all the fault contingencies tested on the 2027 peak load case:

1. Cluster 09 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 09 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-069meets the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCAU model of AF2-069 showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system. These issues are not expected to occur in the field, as they are a result of modeling artifacts associated with the simulation environment and the use of generic renewable models.

AF2-069 GEN1 and GEN2 exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. This issue did not cause instability in the system and the models have been tuned to achieve a faster reactive power output settlement by updating Kc to 0.1 from REPCTA1 module in both generators AF2-069 GEN 1 and AF2-069 GEN2.

High voltage spikes occurred in the simulations immediately after fault clearing for some of the contingencies studied (e.g., P4.06 and P5.13). The voltage spike is a known artifact of the WECC generic renewable models as stated in the WECC Solar Plant Dynamic Model Guidelines: “It should be noted that generic dynamic models for inverter-based generator tend to produce a short-duration (a cycle or shorter) voltage spike at fault inception and clearing. These spikes should be ignored in most cases, as they do not represent the performance of actual hardware. They are simply a consequence of the model’s limited bandwidth, integration time step, and the way current injection models interface with the network solution.”

The tripping of AD1-031 was identified during contingency P5.03 as well as during the Cluster 09 pre-project test; therefore, it has been confirmed that the tripping of AD1-031 is not caused by the TC1 Cluster 09 queue projects. Tripping was avoided for this contingency by updating the undervoltage protection settings. Instance 93405409 was adjusted to 0.5 seconds (30 cycles, adding one cycle to the original P5 fault clearing time of 29 cycles), and instance 93405408 was set to trip if terminal voltage falls below 0.65 pu for more than 0.5 seconds (30 cycles, adding several cycles to the original P5 fault clearing time of 29 cycles) .

The tripping of O29 units (O29 GEN 1 and GEN 2) was identified during contingency P5.04. It has been confirmed that this tripping is not caused by the TC1 Cluster 09 queue projects. Tripping was avoided for this contingency by updating the undervoltage protection settings. For O29 GEN 1, instance 27615703 was adjusted to 0.5 seconds (30 cycles, adding several cycles to the original P5 fault clearing time of 18 cycles). Similarly, for O29 GEN 2, instance 27615803 was updated to 0.5 seconds (30 cycles, adding several cycles to the original P5 fault clearing time of 18 cycles).

No mitigations were found to be required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 11 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 11 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 11 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 11 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 11 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 129 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
5. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 11 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 11 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-441 meets the 0.95 leading and lagging PF requirement.

AF2-441 GEN post fault terminal voltage was more than 1.05 p.u. for several contingencies. This issue did not cause instability in the system and the dynamic models were tuned to achieve a post fault terminal voltage less than 1.05 by adjusting Kc parameter in the REPCA1 module of AF2-441 to 0.1.

The IPCMD and IQCMD states in the REGCAU model of AF2-441 GEN, and AG1-298 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

No mitigations were found to be required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 13 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 13 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 13 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 13 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 13 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 125 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase to ground faults with single-phase delayed clearing due to a stuck breaker (IPO breakers);
6. Three-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 13 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 13 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 13 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-142 and AF2-143 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 model of AF2-142 GEN, AF2-143 GEN, AA1-018 GEN1, AA1-018 GEN2, and AD2-038 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

Voltage spikes over 1.2 pu lasting less than one cycle were observed in some contingencies at Nevada 345 kV, AF2-143 POI, and AE2-281 POI. The voltage spikes are a result of the high reactive current injection of inverter-based generation and instantaneous voltage recovery at fault clearance. Note that RMS simulation is not an accurate tool to evaluate temporary over-voltages produced by inverter-based generation.

Simulations showed AF2-142, AF2-143, and AE1-163 getting stuck in high voltage ride through (HVRT) mode for extended periods after fault clearance for several contingencies. This resulted in a 345 kV POI voltage of about 1.1 pu for more than 5 seconds. For AF2-142 and AF2-143, this was resolved by adjusting the HVRT threshold and deadband to 1.15 pu (from 1.1 pu) and 0.15 pu (from 0.1 pu), respectively. These parameter adjustments were confirmed by the respective project developers. For AE1-163, the dynamic model was updated to the Vestas UDM which was submitted for the AE1-163/AE2-281 necessary study as per the developer’s request.

Initial simulations showed poorly damped oscillations in AC1-111 power. The AC1-111 dynamic model was updated to the most recent (revision 1) model which uses the AC7B exciter model instead of the ESAC1A model. The updated dynamic model eliminated these oscillations.

Sensitivity studies were conducted on more severe scenarios (P4.19.3B1, P4.21.3B1, P4.53.3B3) for Powerton generator stability in the light load case. Initial simulations resulted in a numerical instability for P4.53.3B3 which was resolved by reducing generation at Elwood E.C. such that the pre-contingent loading on Elwood – Goodings Grove 345 kV circuit 11620 is at 100% of RATE A (1201 MVA). The results are stable for the contingencies studied.

No mitigations were found to be required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 14 are listed in              Table 1 below. This report will cover the dynamic analysis of Cluster 14 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 14 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 14 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 14 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 139 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time (and with unsuccessful high speed reclosing);
3. Three-phase bus faults with normal clearing time;
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
5. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
6. Three-phase faults with loss of multiple-circuit tower line (and with unsuccessful high speed reclosing).

There are no three-phase faults with three-phase delayed clearing due to a stuck breaker (GO Breakers with A-contact Logic);

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 14 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 14 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-095 meets the 0.95 leading and lagging PF requirement.

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away from AF2-095. The CSCR revealed minimum and maximum CSCR values of 3.241 for P2.01 and 5.558 for P1.03, respectively.

Nearby queues AC2-154 and AD2-060, located at the same POI (Davis Creek 138 kV) are GNETTED due to the unavailability of updated user defined models that are compatible with PSS/E 34.

The IPCMD and IQCMD states in the REGCAU models of AF2-095 showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system. 

The DVR (Dynamic Voltage Recovery) criteria have been violated under several contingencies (P2.12, P4.33.3B3 and P4.34.3B3)  at the University Park and Wilmington buses were not addressed, given that the DVR recovery envelope was breached at only one bus per contingency — below the threshold of ten or more applicable buses required for mitigation to be considered.

No mitigations were found to be required.

Executive Summary

New Service Requests (AF2-041/AF2-199/AF2-200) in PJM Transition Cycle 1, Cluster 15 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 15 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 15 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 15 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 15 projects were tested for compliance with NERC, PJM, Transmission Owner, and other applicable criteria. Steady-state condition and 76 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run),
2. Three-phase faults with normal clearing time,
3. Three-phase bus faults with normal clearing time,
4. Three-phase faults single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic),
5. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO Breakers with A-contact Logic),
6. Three-phase faults with single-phase delayed clearing due to a stuck breaker (GO Breakers with FD Logic),
7. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic),
8. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the ComEd 345 kV transmission system.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 15 projects were able to ride through the faults (except for faults where protective action trips a generator(s)).
2. The system with Cluster 15 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-041, AF2-199, and AF2-200 meet the 0.95 leading and lagging PF requirement.

AF2-041 exhibited slow reactive power recovery within the 20-second simulation window for several contingencies. This issue did not result in system instability. The model was tuned to improve reactive power settling time by updating the Kp parameter to 2.0, the Ki parameter to 3.0, and setting the VCFlag to 0 in the REPCA1 module.

High voltage spikes occurred in the simulations immediately after fault clearing for some of the contingencies studied. The voltage spike is a known artifact of the WECC generic renewable models as stated in the WECC Solar Plant Dynamic Model Guidelines: “It should be noted that generic dynamic models for inverter-based generator tend to produce a short-duration (a cycle or shorter) voltage spike at fault inception and clearing. These spikes should be ignored in most cases, as they do not represent the performance of actual hardware. They are simply a consequence of the model’s limited bandwidth, integration time step, and the way current injection models interface with the network solution.”

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away from AF2-041/AF2-199/AF2-500. The CSCR revealed minimum and maximum CSCR values of 3.66 for P1.17 and 5.25 for P0.01, respectively.

No mitigations were found to be required.

Table 1: TC1 Cluster 15 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 16 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 16 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 16 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 16 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 16 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 112 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase to ground faults with single-phase delayed clearing due to a stuck breaker (IPO breakers);
6. Three-phase faults with loss of multiple-circuit tower line;

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 16 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 16 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 16 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF1-280, AF2-182, and AF2-349 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 models of AF1-280 GEN, AF2-182 GEN, AF2-349 GEN1, and AF2-349 GEN2 showed erratic behavior for some contingencies in which this generator has been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

Voltage response at Brooke wind generator terminal bus (631215) caused the generator terminal voltage to drop below 0.892 pu resulting in the unit being tripped instantaneously by voltage relay instance 63121502. The relay pickup time was extended to 3 seconds (PRC-024-3 compliant) to prevent the plant from tripping.

Initial simulations showed a poorly damped oscillation in voltage/reactive power at the Easy Road Type 3 Wind plant for contingency P1.02 (fault at AF1-280/AF2-182 POI on Lee County EC 345 kV circuit). Tuning the Torque controller in the Type 3 wind plant resolved the oscillation:

WTTQA1:

CON(J+11) = 0.98 (spd3, shaft speed for power p3 (pu)) from 1.2

CON(J+13) = 1.0 (spd4, shaft speed for power p4 (pu)) from 1.2

Initial simulations showed a poorly damped oscillation in AC1-111 power. The AC1-111 dynamic model was updated to the most recent (revision 1) model which uses the AC7B exciter model instead of the ESAC1A model. The updated dynamic model eliminated these oscillations.

No mitigations were found to be required.

Table 1: TC1 Cluster 16 Projects

Executive Summary

New Service Requests AF1-296, AG1-462 and AG1-553 in PJM Transition Cycle 1, Cluster 17 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 17 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 17 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 17 projects have been dispatched online at maximum power output, with 1.0 pu voltage at the terminal bus, except AF1-296, which was allowed to have a terminal voltage of 1.027 pu.

Cluster 17 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 197 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase faults with single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic).
5. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO Breakers with A-contact Logic);
6. Three-phase faults with single-phase delayed clearing due to a stuck breaker (GO Breakers with FD Logic);
7. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
8. Single-phase faults with stuck breaker (for MISO substations);
9. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
10. Single-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure (for MISO substations);
11. Three-phase faults with loss of multiple-circuit tower line.

No relevant high-speed reclosing (HSR) contingencies were identified for this study.

Buses at which the faults listed above were applied are:

• Cordova E.C. TSS 940 (AG1-553/AG1-462 POI) 345 kV
• Cordova M.E.C. 345 kV
• Nelson TSS 155 (AE1-134/AA2-030/AA1-146 POI) 345 kV
• E. Molin (Barstow SUB. 39 M.E.C.) 345 kV
• Quad Cities STA. 4 345 kV
• Garden Plain TSS 132 (AF1-296 POI) 138 kV
• Nelson TSS 155 138 kV
• AF2-392 TAP 138 kV
• Sterling Steel (ESS H71) 138 kV
• Rock Falls TSS 133 138 kV
• Albany S.S. 138 kV & 161 kV
• Beaver Channel 161 kV
• York 161 kV
• Savanna 161 kV
• Rock Creek 161 kV
• SUB 49 161 kV

For all simulations, the queue projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 17 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 17 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AG1-553, AG1-462 and AF1-296 meet the 0.95 leading and lagging PF requirement.

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away of Cluster 17. The CSCR results for AF1-296 are summarized in Table 7 through Table 17 and revealed a minimum and maximum CSCR values of 2.64 for P4.84 & P4.86 and 4.45 for P1.64, respectively. The CSCR results for AG1-553 and AG1-462 revealed a minimum and maximum CSCR values of 3.81 for P4.08 & P4.10 and 7.24 for P1.02 & P4.03, respectively.

Specific findings from the simulations for each of the queue projects of Cluster 17 are indicated below.

AG1-553 and AG1-462

The IPCMD and IQCMD states in the REGCA1 models of AG1-553 GEN 1&2 and AG1-462 GEN 1 showed erratic behavior for some contingencies in which AG1-553 or AG1-462 generators have been disconnected as part of the contingency event. Since the machines are disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

High voltage spikes on the terminal voltages of AG1-462 and AG1-553, occurred in the simulations immediately after fault clearing for a few of the contingencies studied (i.e. fault where spike is observed). The voltage spike is a known artifact of the WECC generic renewable models as stated in the WECC Solar Plant Dynamic Model Guidelines: “It should be noted that generic dynamic models for inverter-based generator tend to produce a short-duration (a cycle or shorter) voltage spike at fault inception and clearing. These spikes should be ignored in most cases, as they do not represent the performance of actual hardware. They are simply a consequence of the model’s limited bandwidth, integration time step, and the way current injection models interface with the network solution.”

AF1-296

For 24 contingencies out of 197, the steady state post-contingency terminal voltage of AF1-296 went slightly above 1.05 pu (Et ≈ 1.056 pu – 14 contingencies, Et ≈ 1.051 pu – 10 contingencies). This is due to the fact that the terminal voltage of AF1-296 pre-contingency is 1.027 pu.

High voltage spikes at the terminals of AF1-296 and its POI, Garden Plain 138 kV, occurred in the simulations immediately after fault clearing for some of the contingencies studied (i.e. fault where spike is observed]). As, with the WECC models, these voltage spikes are considered a consequence of the model’s limited bandwidth, integration time step and the way it interfaces with the network solution. Therefore, it is estimated that they do not represent the performance of actual equipment and can be ignored in most cases. The spike at Garden Plain is a consequence of the spike at the terminals of AF1-296.

No mitigations were found to be required. However, it is recommended that the developer of AF1-296 provides an adjusted model that allows specifying the generator’s reactive power output at levels that support initial conditions with a terminal voltage close to 1.0 pu.

Table 1: Cluster 17 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 21 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 21 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 21 projects will meet the dynamics requirements of the NERC, ComEd and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 21 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 21 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 39 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run),
2. Three-phase faults with normal clearing time,
3. Three-phase faults with single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic),
4. Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic).

No relevant high-speed reclosing (HSR) contingencies nor single-phase bus faults were identified for this study.

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the ComEd 345 kV transmission system.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

1. Cluster 21 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 21 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AG1-374 meets the 0.95 leading and lagging PF requirement.

The AE1-205 unit tripped by undervoltage relays for 4 contingencies (P4.23, P4.24, P4.25, and P4.26). Contingencies P4.23, P4.24, P4.25, and P4.26 involved a three-phase stuck breaker fault at Pontiac Midpoint 345 kV clearing in 13 cycles. As per NERC Standard PRC-024 requirements, these contingencies were found to meet the corresponding NERC PRC-024 LVRT criteria. A similar tripping issue was observed in AF2-252/AF2-352 dynamic study.

Fictitious post-fault overvoltage tripping at AF2-252 and AF2-352 generator buses tripped the queue projects due to the action of instantaneous over-voltage relays for contingencies P1.02, P1.03, P4.10, P4.25 and P4.26. Therefore, the relay pickup times for voltage relay instances 96061504 and 95961504 were set to 0.0305 seconds to avoid fictitious voltage tripping of the units. With this updated relay settings only P1.03 was tripping. Both relay instances have been updated to 0.035 seconds to avoid this tripping.

The IPCMD and IQCMD states in the REGCAU model of AG1-374 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away from Cluster 21. The CSCR results are summarized in Table 8 through Table 11 and revealed a minimum and maximum CSCR values of 3.11 for P4.15, P4.16, P4.19 and P4.20 and 7.02 for P1.04, respectively.

No mitigations were found to be required.

Table 1: TC1 Cluster 21 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 23 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 23 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 23 projects will meet the dynamics requirements of the NERC, Dayton and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 23 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer. Four dispatch scenarios were considered for AG1-323, which is a hybrid solar/storage project where the aggregate machine capability exceeds MFO. The dispatch scenarios are given in the following table.

AG1-323 Dispatch Scenarios

Cluster 23 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 193 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady-state operation (20 second run);

       b)       Three-phase faults with normal clearing time;

       c)       Single-phase bus faults with normal clearing time;

       d)       Single-phase faults with stuck breaker;

       e)       Single-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;

       f)       Single-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 23 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

       a)       Cluster 23 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 23 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.

       c)       Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).

       d)       No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AE1-092 and AG1-323 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 models of AE1-092 GEN, AG1-323_GEN1 and AG1-323_GEN2 showed erratic behavior for some contingencies in which this generator has been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

No mitigations were found to be required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 24 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 24 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 24 projects will meet the dynamics requirements of the NERC, EKPC and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 24 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 24 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 154 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady-state operation (20 second run);

       b)       Three-phase faults with normal clearing time;

       c)       Single-phase bus faults with normal clearing time;

       d)       Single-phase faults with stuck breaker;

       e)       Single-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;

       f)       Single-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 24 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

       a)       Cluster 24 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 24 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.

       c)       Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).

       d)       No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF1-233 and AF2-307 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCAU model of AF1-233 GEN and AF2-307 GEN showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

Dynamic simulations showed that AF2-307 inverter reactive power output was being limited by the inverter controls (REECA1) below the 0.95 dynamic power factor requirement. The issue was resolved in consultation with the developer  by adjusting the inverter control parameters as follows:

•       REECA1:

o       CON(J+15) = 2 (VMAX (pu), Max. limit for voltage control) from 1.1

o       CON(J+16) = 0 (VMIN (pu), Min. limit for voltage control) from 0.9

AF2-111 exhibited slow reactive power recovery within the 20 second simulation window for several contingencies. This issue did not cause instability in the system.

No mitigations were found to be required.

Table 1: TC1 Cluster 24 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 25 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 25 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 25 projects will meet the dynamics requirements of the NERC, EKPC and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 25 projects have been dispatched online at maximum power output, and voltage schedules set to achieve near unity power factor at the high side of the main transformer.

       Cluster 25 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 133 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady-state operation (20 second run);

       b)       Three-phase faults with normal clearing time;

       c)       Single-phase bus faults with normal clearing time;

       d)       Single-phase faults with stuck breaker;

       e)       Single-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;

       f)       Single-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 25 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

       a)       Cluster 25 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 25 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.

       c)       Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).

       d)       No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AG1-354 and AG1-471 meet the 0.95 leading and lagging PF requirement.

AG1-471 generator unit remained at High Voltage Ride Through mode for several  contingencies. As a result, the AG1-471 generator terminal voltage remained at approximately 1.12 pu after fault recovery which exceeds the range of 0.95 pu – 1.05 pu. This issue caused the voltage relay stage set to 1.1 pu for 10 seconds to pick up and trip AG1-471 generating unit. Modifying CON(J+1): Vup to 1.16 pu of the REECA1 model resolved the issue of AG1-471 getting stuck in HVRT mode and resolved the tripping of the unit. The AG1-471 developer confirmed that the proposed settings .

No mitigations were found to be required.

Table 1: TC1 Cluster 25 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 26 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 26 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 26 projects will meet the dynamics requirements of the NERC, EKPC and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 26 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 26 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 139 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady-state operation (20 second run);

       b)       Three-phase faults with normal clearing time;

       c)       Single-phase bus faults with normal clearing time;

       d)       Single-phase faults with stuck breaker;

       e)       Single-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;

       f)       Single-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 26 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

       a)       Cluster 26 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 26 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.

       c)       Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).

       d)       No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AE2-308 meets the 0.95 leading and lagging PF requirement.

ETERM of AE2-308 GEN went outside the range of 0.95 pu - 1.05 pu in post fault for several contingencies. This issue did not cause instability in the system.

The IPCMD and IQCMD states in the REGCA1 model of AE2-308 GEN showed erratic behavior for some contingencies in which this generator has been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, these plots are ignored.

Due to the breaker configuration at the AE2-308 Point of Interconnection (POI), there is a potential risk of an islanding condition in which AE2-308 could become the sole power source for the load at Three Forks if both the Fawkes and Dale circuits are lost. This scenario could occur during a stuck breaker contingency, where the breaker between the Fawkes and Dale circuits fails to operate. The AE2-308 inverter control strategy includes passive anti-islanding protection. Under this strategy, if the facility becomes islanded, the voltage and/or frequency magnitude at the inverter terminals will rapidly reach set protection thresholds, causing the inverters to trip.

Poorly damped oscillations in the rotor speeds and active power of the 1HAEFLING units 1 and 2 were observed for most contingencies. Select contingency was studied without TC1 projects dispatched. The oscillations persists without TC1 projects. Therefore, the issue is not a result of the addition of TC1 projects. Note that these units are using a simple GENCLS model, without an exciter or power system stabilizer.

No mitigations were found to be required.

Table 1: TC1 Cluster 26 Projects

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1, Cluster 27 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 27 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 27 projects will meet the dynamics requirements of the NERC, EKPC and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. Cluster 27 projects have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

Cluster 27 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 209 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady-state operation (20 second run);

       b)       Three-phase faults with normal clearing time;

       c)       Single-phase bus faults with normal clearing time;

       d)       Single-phase faults with stuck breaker;

       e)       Single-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;

       f)       Single-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the Cluster 27 projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2027 peak load case:

       a)       Cluster 27 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 27 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.

       c)       Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).

       d)       No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF2-111 and AG1-526 meet the 0.95 leading and lagging PF requirement.

The provided AF2-111 power plant controller model (REPCA1) did not include a reactive power droop on the voltage controller. It is expected to have a reactive power droop to avoid any interactions with the other plants in the AC system. This was resolved in consultation with the AF2-111 developer  by adding a 5% droop to Q/V controller in the plant controller model (REPCA1).

The provided AG1-526 power plant controller model (REPCA1) did not include a reactive power droop on the voltage controller. It is expected to have a reactive power droop to avoid any interactions with the other plants in the AC system. This was resolved in consultation with the AG1-526 developer  by adding a 5% droop to Q/V controller in the plant controller model (REPCA1).

Poorly damped oscillations in the rotor speeds and active power of the 1HAEFLING units 1 and 2 were observed for most contingencies. It was observed that the oscillations persist without TC1 projects.  Therefore, the issue is not a result of the addition of TC1 projects. Note that these units are using a simple GENCLS model, without an exciter or power system stabilizer.

No mitigations were found to be required.

Table 1: TC1 Cluster 27 Projects

Executive Summary for Dynamic Stability Analysis using PSSE

New Service Requests (projects) in PJM Transition Cycle 1 Cluster 29 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 29 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 29 projects will meet the dynamics requirements of the NERC, Dominion Energy, and PJM reliability standards.

The load flow case finalized for Phase 2 was used as a starting point and was updated based on latest Cluster 29 data, Dominion Energy recommended transmission changes and withdrawn generation. Projects in vicinity of Cluster 29 have been dispatched online at maximum power output with near unity power factor measured at the high-side of the main substation transformer. The dynamic models for Cluster 29 projects were updated based on the latest DP2 data and include any tuning adjustments recommended during Phase 2.

This analysis currently was performed using the PSSE library models provided the developer.  Dominion Energy Transmission provided the models for the FACT’s devices for the AF1-123, AF1-124, and AF1-125 queue projects.

Cluster 29 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. 133 contingencies were studied, each with a 20 second simulation time period. The studied contingencies included:

• Steady-state operation (30 seconds)
• Three-phase faults with normal clearing time
• Single-phase bus faults with normal clearing time
• Single-phase faults with stuck breaker
• Single-phase faults with delayed clearing at remote end
• Single-phase faults with loss of multiple-circuit tower line.

For all simulations, the projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

The results of the analysis were evaluated against the following recovery criteria per PJM’s Regional Transmission Planning Process and Transmission Owner criteria:

• Cluster 29 projects were able to ride through the faults (except for faults where protective action trips a generator(s)).
• The system with Cluster 29 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
• Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus) and the final voltages are within the steady-state voltage ranges below per Dominion Energy’s transmission planning criteria.
• P1 Category Contingencies:
• 0.93 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.93 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.01 to 1.096 p.u. for 500 kV facilities
• P2, P4, P5, and P7 Category Contingencies:
• 0.90 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.90 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.00 to 1.096 p.u. for 500 kV facilities
• No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AF1-123, AF1-124 and AF1-125 met the 0.95 lagging and leading power factor requirements at the point of interconnect (POI) at Harpers 230 kV substation.

The results of the analysis identified that the addition of the AF1-123, AF1-124 and AF1-125 queue projects resulted in instability in a majority of contingencies. The following mitigation is required to maintain stability:

• Add a second 500 kV line from the Updated Fentress to the Yadkin substations
• Add two 230 kV gas-insulated lines (GILs) from the existing Fentress to the New Fentress substations
• All 230 kV breakers (212822, 269T2128, 26922, 224022-1, 224022-2, 208722, W22, L122, L322, H22, SC122, SC322, SC422, SV122, and the new breakers G1 and G2 for the gas insulated lines) at Fentress 230 kV Substation require a 14 cycle clearing time
• Dual pilot protection is required for the Fentress to AD1-033 POI 230 kV line circuit 2240

No voltage or frequency protection trips occurred for AF1-123, AF1-124 and AF1-125 queue projects using the settings provided.

The AF1-123, AF1-124 and AF1-125 queue projects exhibited slow active power recovery after the fault cleared and this is recovery was expected based on the model documentation provided for the OEMs’ wind turbine. The WGOWECC controller, clamps the active power at 95% for up to 5 seconds to ensure steady recovery of the system and then releases the active power to 100% to restore full operation.

An EMT analysis and stability analysis using a PSS/E user defined model is recommended for AF1-123, AF1-124 and AF1-125 due to the CSCR values being less than 3. A user defined model is under development by the IC and it will be evaluated as a sensitivity once the model initializes properly.

AE2-156 reactive power and terminal voltage recovery was not settling to a steady state value during the analysis. However, it was observed that reactive settling doesn’t violate PJM or Dominion’s criteria. The models were tuned to achieve a faster recovery in Cluster 46 Phase 2 Stability Analysis.

AE2-051 reactive power and terminal voltage recovery was not settling to a steady state value during the analysis. The models can be tuned to achieve a faster recovery upon request.

AB2-169 generator tripped for overvoltage’s above 1.25 p.u. The unit rode through when the pickup timer  was increased from 0.0 seconds to 0.0125 seconds.

Executive Summary for Dynamic Stability Analysis using PSCAD/EMT

The EMT dynamic performance analysis was revelated with the latest PSCAD models pprovided by CVOW (AF1-123, 124 & 125) generation developer.   A detailed model quality testing was performed. Below are some deficiency and corresponding update that were applied to the plant model.

• CVOW initialization issues were cured by using a stiff voltage source model at POI during the initialization period and disconnected later in the simulation.
• Pi-circuit equivalents for 66 kV IAC cables were updated to Bergeron models using best available data.
• Onshore cable section was updated into onshore and HDD sections using best available data.
• Earthing transformer model was included at the 66 kV delta winding of OSS transformer.
• OSS LTC transformer taps were set to match values used for TC1 analysis.
• Harpers STATCOM model was updated to latest OEM model.

Preliminary results of CVOW performance for Summer peak and Light Load system conditions for select TPL contingencies indicate the following:

• Instability of the project post-fault was observed for select P1 and P6 contingencies prior to the inclusion of all proposed upgrades.
• With the inclusion of the proposed upgrades namely the 500 kV Line 5005 between Fentress and Yadkin and two GIL circuits between new and existing Fentress 230 kV, CVOW fully recovers post-fault for a severe P4 contingency.
• The preliminary results demonstrate the impact of the weak system strength and the improvements provided by the proposed upgrades.
• Analysis of CVOW performance for severe P6 contingencies with the proposed upgrades is ongoing.
• Investigation of partial nuisance tripping of CVOW post-fault is also on-going for other contingencies and system conditions.

CVOW Flicker

Preliminary analysis shows flicker issue induced by CVOW project. Preliminary flicker analysis was conducted using a range of ramp rates in the absence of data on power fluctuation in response to wind speed variation. To assess flicker impact, MEPPI evaluated multiple wind profiles, spanning from conservative scenarios to less conservative ramp rates. Results indicate that the ramp rate significantly influences the flicker observed at the POI and we violate the criteria of 1 Pst for various profiles considered. Flicker analysis was performed in PSCAD using detailed models of the CVOW project and a system equivalent at the POI.  In order to mitigate the flicker issue an addition of 300 MVAR STATCOM will need to be installed at Fentress 230 kV Substation.

Note:

TC1 Phase 3 Dynamic  Stability analysis has been completed by using library model provided in TC1 Phase 2.  For TC1 Phase 3, a PSSE User Defined Model was requested due to low SCR concerns in the area. The CVOW project developer provided a User Defined Model that did not work properly in the TC1 base case. The CVOW  project development team is actively working on getting an updated User Defined Model for the AF1-123/AF1-124/AF1-125 projects from Siemens Gamesa Renewable Energy (SGRE). This updated model was not ready at the time TC1 Phase 3 studies concluded, and CVOW will need to initiate a Necessary Study request post GIA to have the updated User Defined Model provided to PJM to perform a Dynamic Stability analysis for the AF1-123/AF1-124/AF1-125 projects.

Also, CVOW notified PJM of a change for nineteen (19) of the GSUs that are planned to be installed for the CVOW Project for Queue Position AF1-123 (OSS T1L11). Note that these 19 GSUs – installed in 19 of the 59 wind turbine generators – have been manufactured and have higher impedance values that was in the original design. Following evaluation, it has been determined that these changes in impedances to these 19 units do not affect the MFO/gross output, have very limited changes for the  losses, and the MW output at the POI will be changed, but insubstantially. The other queues AF1-124 & AF1-125 are unchanged/unaffected. This GSU change for AF1-123 will also be evaluated as part of the Necessary Study being requested above.

Bellow are some of the item that will be captured during post GIA Necessary study request for CVOW project.

1. The User Defined Model dynamic stability analysis for AF1-123/AF1-124/AF1-125 as well as the GSU change for AF1-123.
2. The EMT Analysis is based on PSCAD Models provided to PJM & DEV-ET on May 19^th, the developers needs to confirm that these models are still valid and if updates to these models need to be made to represent changes made in the UDM please provide updated EMT models.
3. As identified in the TC1 Phase 2 Reports and the June 2025 “EMT Generation Model Review” Report Nuisance Tripping is still occurring which can result in up to 1600 MW Tripping Off-Line.  This tripping is being initiated by the DC Protection Scheme of the WTGs, the developer needs to provide a solution to PJM & DEV-ET for this deficiency.   This solution will be evaluated in the NSA to determine if it resolves the nuisance tripping issue.  
4. The developer needs to indicate if margin can be increased in the Over-Voltage Ride Through, Under Voltage Ride Through & Frequency Ride-Through to increase the margins from the PRC-024 & IEEE 2800 Requirements as identified in the TC1 Phase 2 Reports and the June 2025 “EMT Generation Model Review” Report.
5. Preliminary Study Results indicate that the CVOW Project will result in a Pst Value greater than 1.  This will adversely impact Dominion’s Customers the proposed solution to this flicker issue will be to install a 300 MVAR STATCOM at Fentress Substation on the 230 kV Bus.   The developer can provide updated Ramp Rates  as part of the NSA to determine if mitigation is still required.

Executive Summary

New Service Requests (projects) in PJM Transition Cycle 1 Cluster 30 for Phase 3 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 30 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 30 projects will meet the dynamics requirements of the NERC, Dominion Energy, and PJM reliability standards.

The load flow case for Phase 2 was used as a starting point and was updated based on latest Cluster 30 data, recommended transmission changes incorporated based on Dominion Energy Phase 2 feedback, and withdrawn generation removed. Cluster 30 projects have been dispatched online at maximum power output with near unity power factor measured at the high-side of the main substation transformer. The dynamic models for Cluster 30 projects were updated based on the latest DP2 data and include any tuning adjustments recommended during Phase 2.

Cluster 30 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. During the Phase 2 analysis contingencies were examined around the POIs and no violations were observed as a result of Cluster 30 projects interconnecting.  Due to this the Phase 3 analysis for Cluster 30 focused on the contingencies at Chase City that resulted in instability caused by Cluster 31 and Cluster 40 during Phase 2.  The Phase 3 analysis examined, 8 initial contingencies and 24 sensitivity contingencies were studied, each with a 30 second simulation time period. The studied contingencies included:

• Three-phase faults with normal clearing time.
• Single-phase bus faults with normal clearing time.
• Single-phase faults with stuck breaker.

Instability was observed for contingencies when the Chase City to AG1-285 Tap 115 kV circuit was tripped. This outage resulted in instability due to insufficient export paths for the generation along the Farmville to Chase City 115 kV path through the radial connection.  Additionally, the Farmville to Chase City 115 kV path is prone to controller instability due to weak grid conditions determined by the composite short circuit ratio assessment.  The instability was caused by the Cluster 31 queue projects. 

To following mitigation was tested and all maintain stability:

1. Adding a new 115 kV line from AG1-285 to Butcher’s Creek.
2. Moving AF2-222 and AG1-285 to a new 230 kV line from Farmville to Finneywood.
3. Upgrade the new AG1-285 substation to a breaker and a half scheme to accommodate 2 x 230/115 kV transformers and a 230 kV line from AG1-285 to Finneywood .

The Transmission Owner has elected to upgrade the new AG1-285 substation to a breaker and a half scheme to accommodate 2 x 230/115 kV transformers and a 230 kV line from AG1-285 to Finneywood as the mitigation to the instability. This mitigation is required due to the interconnection of the Cluster 31 queue projects. Cluster 30 queue projects did not cause the instability. The mitigation was further tested for all Phase 2 contingencies and no violations were observed.

Nearby projects were found to trip based on their protection settings. The protection trip times were increased during Phase 2 analysis and maintained during the Phase 3 analysis:

• AE1-056 tripped for frequencies below 55 hz for more than 0.001 seconds and the relay pick-up time was increased to 0.034 seconds
• AE1-056 tripped for frequencies above 65 hz for more than 0.001 seconds and the relay pick-up time was increased to 0.020834 seconds
• AF2-222 tripped for voltages above 1.3 p.u. for more than 0.001 seconds and the relay pick-up time was increased to 0.012501 seconds

With the mitigation identified above, the results of the contingencies tested on the RTEP 2027 summer peak case found:

• Cluster 30 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
• The system with Cluster 30 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for inter area modes and 4% for local modes.
• Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus) and the final voltages are within the steady-state voltage ranges below per Dominion Energy’s transmission planning criteria.
• P1 Category Contingencies:
• 0.93 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.93 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.01 to 1.096 p.u. for 500 kV facilities
• P2, P4, P5, and P7 Category Contingencies:
• 0.90 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.90 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.00 to 1.096 p.u. for 500 kV facilities
• No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

No mitigation was needed to connect the Cluster 30 queue projects.

Executive Summary for Dynamic Stability Analysis Using PSSE

New Service Requests (projects) in PJM Transition Cycle 1 Cluster 31 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 31 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 31 projects will meet the dynamics requirements of the NERC, Dominion Energy, and PJM reliability standards.

The load flow case for Phase 2 was used as a starting point and was updated based on latest Cluster 31 data, Dominion Energy recommended transmission changes and withdrawn generation. Cluster 1 projects have been dispatched online at maximum power output with near unity power factor measured at the high-side of the main substation transformer. Two sets of modeling data were available for Cluster 31 projects for either a 115 kV Point of Interconnection (POI) or a 230 kV POI based on Phase 2 mitigation. Any tuning required for queue projects, other than AF2-222 and AG1-285, was included as the starting point for the Phase 3 analysis.

Cluster 31 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. 136 initial contingencies and 169 sensitivity contingencies were studied, each with a 30 second simulation time period. The studied contingencies included:

• Steady-state operation (30 seconds)
• Three-phase faults with normal clearing time
• Single-phase bus faults with normal clearing time
• Single-phase faults with stuck breaker
• Single-phase faults with delayed clearing at remote end
• Three-phase faults with loss of multiple-circuit tower line.

During the analysis, instability was observed when the Chase City to AG1-285 Tap 115 kV circuit was tripped. This outage resulted in instability due to insufficient export paths for the generation along the Farmville to Chase City 115 kV path through the radial connection.  Additionally, the Farmville to Chase City 115 kV path is prone to controller instability due to weak grid conditions determined by the composite short circuit ratio assessment. 

To following mitigation was tested and all maintain stability:

1. Adding a new 115 kV line from AG1-285 to Butcher’s Creek.
2. Moving AF2-222 and AG1-285 to a new 230 kV line from Farmville to Finneywood.
3. Upgrading the new AG1-285 230 kV substation to a breaker and a half scheme to accommodate 2 x 230/115 kV AG1-285 transformers, and a 230 kV line from AG1-285 to Finneywood.

The Transmission Owner selected the 3^rd mitigation option (N9630) which includes a new AG1-285 230 kV substation to a breaker and a half scheme to accommodate 2 x 230/115 kV AG1-285 transformers, and a 230 kV line from AG1-285 to Finneywood to mitigate the instability. This mitigation is required due to the interconnection of the Cluster 31 queue projects.

The Chase City to Finneywood 230 kV line and the Chase City to AG1-285 115 kV line cannot share a common tower or instability would occur for a P7 of these lines.

Nearby projects were found to trip based on their protection settings. The contingencies met the evaluation criteria with and without the protection enabled. The revised pickup timers were not determined to expediate Cluster 31 study completion.

• AE1-056 tripped for frequencies below 55 Hz for more than 0.001 seconds
• AE1-056 tripped for frequencies above 65 Hz for more than 0.001 seconds.
• AF2-222 tripped for voltages above 1.3 p.u. for more than 0.001 seconds.

The protection settings for AE2-259 regarding frequency above 62.5 Hz for more than 0 seconds and frequencies below 56.5 Hz for more than 0 seconds are commented due to tripping of the generator during the Phase 3 analysis. The IC should be contacted to provide the maximum pickup time that the facility can withstand.  The contingencies met the evaluation criteria with and without the protection enabled. The revised pickup timers were not determined to expediate Cluster 31 study completion.

With the mitigation identified above, the results of the contingencies tested on the RTEP 2027 summer peak case found:

• Cluster 31 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
• The system with Cluster 31 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
• Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus) and the final voltages are within the steady-state voltage ranges below per Dominion Energy’s transmission planning criteria.
• P1 Category Contingencies:
• 0.93 to 1.05 p.u. for 230, 115, 69 kV facilities\
• 0.93 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.01 to 1.096 p.u. for 500 kV facilities
• P2, P4, P5, and P7 Category Contingencies:
• 0.90 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.90 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.00 to 1.096 p.u. for 500 kV facilities
• No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

However, the AG1-285 queue project was not able to maintain voltages below 1.1 p.u during the lagging power factor assessment test.  

The AF2-222 queue project updated the make and model of inverter between the DP1 and DP2 data submittals. Due to this a sensitivity was performed to determine the impacts of the inverter change using the Sungrow SG4400UD-MV-US inverter provided during DP2. For the sensitivity the AF2-222 was modeled using the generator, inverter step up transformer and collector system equivalent data from DP2 to consider the inverter change.  The main station transformer and attachment line were modeled using DP1 data to consider the 115 kV POI.  Network Upgrade 3 was used for this sensitivity to determine the impacts of the inverter change after mitigating the instability.

The results of the sensitivity determined that AF2-222 was freezing for some contingencies using the Sungrow SG4400UD-MV-US inverter, this issue was resolved when REECA1 Vdip is changed from 0.9 p.u. to 0.8 p.u. The IC should be contacted to validate the above setting. It’s assumed the developer DP3 data submittal would include the Sungrow SG4400UD-MV-US inverters.

Executive Summary for Dynamic Stability Analysis Using  PSCAD/EMT

Model Quality Testing Report

PSCAD model for Queue project AF2-222 and AG1-285 was developed and tested individually to ensure the model was in compliance with the PJM requirements. Test summary and result of test been summarized below in table 2. it is confirmed that PSCAD model was set up properly and satisfied the PJM requirement.

Weak Grid Assessment

This Weak Grid Assessment evaluates two projects from PJM Transition Cycle 1 (TC1) Cluster 31 for risk of voltage instability due to weak grid conditions in an EMT simulation environment.  The two projects, AF2-222 and AG1-285, were identified in the Cluster Study as having risk of undamped oscillations during a contingency condition and indicating system instability after dynamic simulation analysis in PSS/E. Three potential network upgrades were considered to resolve this instability, and Network Upgrades 2 and 3 were shown to be effective through sensitivity analysis.

This assessment, completed by INS Engineering, aims to verify the impact of Network Upgrade 2 and 3 identified in the Cluster Study, using detailed models in an EMT simulation.  Summary descriptions of each project and the two network upgrades are listed below:

The following network upgrades proposed as mitigation in cluster 31 are evaluated in this weak grid assessment:

• Network Upgrade 2: Moving AF2-222 and AG1-285 to a new 230 kV line from Farmville to Finneywood
• Evaluated in the main body of this report
• Network Upgrade 3: Upgrading the new AG1-285 230 kV substation to a breaker and a half scheme to accommodate 2 x 230/115 kV AG1-285 transformers, and a 230 kV line from AG1-285 to Finneywood
• Evaluated in Appendix B
• This option has been selected by the Transmission Owner

First, the individual project PSCAD models were evaluated for data consistency and model performance as part of the standard Model Quality Test in [2] and [3], with model updates being made where needed.  INS confirmed that the PSCAD models were set up properly and satisfied the requirements of PJM. After satisfactory configuration and performance of the individual projects were obtained, the models were integrated into a translated reduced network in PSCAD to create an overall detailed system model. 

For Network Upgrade 2, two representative contingency cases from the Cluster Study, considered effectively the worst case in terms of risk for weak grid instability, were simulated in the PSCAD detailed system model. For Cluster 31, the following contingency cases were chosen.

• P=1.0pu, 3LG fault, 150ms, on AF2-171 POI to Farmville 230kV and loss of circuit
• P=1.0pu, 3LG fault, 150ms, on AG1-427 to Finneywood 230kV and loss of circuit

Simulation results in PSCAD are summarized below.  It can be observed that both contingency cases using the detailed PSCAD system model results in a stable recovery, matching the results of the Cluster Study. 

For Network Upgrade 3, three representative contingency cases from the Cluster Study, considered effectively the worst case in terms of risk for weak grid instability, were then simulated in the PSCAD detailed system model. Simulation results in PSCAD are summarized below.  It can be observed that all three contingency cases using the detailed PSCAD system model results in a stable recovery, matching the results of the Cluster Study. 

The results of this assessment show stable recovery in worst-case contingencies using either Network Upgrade 2 or 3, and support the conclusion from the Cluster Study that these proposed network upgrades mitigate the identified weak grid instability issues.

Executive Summary for Dynamic Stability Analysis using PSSE

New Service Requests (projects) in PJM Transition Cycle 1 Cluster 32 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 32 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 32 projects will meet the dynamics requirements of the NERC, Dominion Energy, and PJM reliability standards.

 Table 1: Transition Cycle 1 Cluster 32 Projects

The load flow case finalized for Phase 2 was used as a starting point and was updated based on latest Cluster 32 data, Dominion Energy recommended transmission changes and withdrawn generation. Projects in vicinity of Cluster 32 have been dispatched online at maximum power output with near unity power factor measured at the high-side of the main substation transformer. The dynamic models for Cluster 32 projects were updated based on the latest DP2 data and include any tuning adjustments recommended during Phase 2.

Cluster 32 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. 116 contingencies were studied, each with a 30 second simulation time period. The studied contingencies included:

• Steady-state operation (30 seconds)
• Three-phase faults with normal clearing time
• Single-phase bus faults with normal clearing time
• Single-phase faults with stuck breaker
• Single-phase faults with delayed clearing at remote end
• Single-phase faults with loss of multiple-circuit tower line.

The contingencies were updated based on topology changes due to any Dominion Energy recommended transmission changes or generation withdrawals.

For all simulations, the projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

Instability was observed for certain contingencies resulting in the outage of the Northern Neck and AE1-155 Tap 115 kV line. The instability was mitigated by adding in a second 115 kV line from Northern Neck to AE1-155 Tap (Moon Corner). This new line would require additional breakers at Moon Corner and Northern Neck Both lines should not share a common breaker such that a breaker failure or stuck breaker could take out both Northern Neck – AE1-155 115 kV lines. Both lines should not share a common tower or structure such that a tower or structure failure could take out both lines.

A load flow analysis network update that reconductors the Northern Neck to Rappahannock 115 kV was considered and was not required to meet the evaluation criteria for the CL32 Stability Analysis.

With the addition of the second 115 kV line from Northern Neck to AE1-155 Tap, the study found that the following generators protection trips occurred. The relay pick-up settings were increased to allow the generators to ride through and should be confirmed with the generator owner.

• AE2-041 tripped for voltages below 0.65 p.u. for more than 0.35 seconds and the relay pick-up time was increased to 0.4334 seconds to able to ride through the faults.
• AF1-018 tripped for voltages below 0.65 p.u. for more than 0.35 seconds and the relay pick-up time was increased to 0.4334 seconds to able to ride through the faults.
• AG1-038 tripped for voltages above 1.20 p.u. for more than 0.045 seconds and the relay pick-up time was increased to 0.0501 seconds to able to ride through the faults.

Reactive power for AF1-114 and AF2-091 does not appear to settle within the 30 seconds simulation for some contingencies. This did not violate any criteria nor create instability. AF1-114 and AF2-091 currently utilize a 4% voltage reactive droop. If a faster reactive power settling is desired in the future, then the model can be tuned to improve the reactive recovery later.

With the new 115 kV transmission line mitigation identified above, the results of the contingencies tested on the RTEP 2027 summer peak case found:

• Cluster 32 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
• The system with Cluster 32 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for inter area modes and 4% for local modes.
• Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus) and the final voltages are within the steady-state voltage ranges below per Dominion Energy’s transmission planning criteria.
• P1 Category Contingencies:
• 0.93 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.93 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.01 to 1.096 p.u. for 500 kV facilities
• P2, P4, P5, and P7 Category Contingencies:
• 0.90 to 1.05 p.u. for 230, 115, 69 kV facilities
• 0.90 to 1.03 p.u. for 138 kV facilities due to legacy switches
• 1.00 to 1.096 p.u. for 500 kV facilities

No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

Executive Summary for Dynamic Stability Analysis using PSCAD/EMT

Model Quality Testing Report

PSCAD model for Queue project AF2-120, AG1-135, AG1-146/147 and AG1-536 was developed and tested individually to ensure the model was in compliance with the PJM requirements. Test summary and result of test been summarized below in table 2. it is confirmed that PSCAD model was set up properly and satisfied the PJM requirement.

Weak Grid Assessment

This Weak Grid Assessment evaluates five projects from PJM Transition Cycle 1 (TC1) Cluster 32 for risk of voltage instability due to weak grid conditions in an EMT simulation environment.  The five projects, AF2-120, AG1-135, AG1-146, AG1-147, and AG1-536, were identified in the Cluster Study as having risk of undamped oscillations in multiple contingency cases, indicating system instability after dynamic simulation analysis in PSS/E. A network upgrade, a new second 115 kV transmission line from Northern Neck to AE1-155 Tap, was recommended along with evaluation using detailed models in an EMT simulation.

This assessment, completed by INS Engineering, aims to evaluate the risk of weak grid instability and verify the effectiveness of the recommended network upgrade in EMT simulation.  A summary description of each project is listed below: