AF2-078 System Impact Study Report

This project is eligible for the Expedited Study process per PJM Tariff Part VII, Subpart B, section 304 and will follow the Expedited Study Process rules outlined in PJM Manual 14H, Attachment I.3.4.

Projects in the Expedited Process will receive a retooled System Impact Study report with the Transition Cycle #1 projects (AE1-AG1) removed from the base case model used for their study. This System Impact Study (SIS) report has been prepared for the AF2-078 project using the updated case model. PJM performed reliability analysis for the project based on the serial study approach using the legacy Generator Deliverability Study method outlined in Manual 14B, Attachment C.3 (Revision 51 of M14B). Summer peak and light load load flow analysis was performed. Short circuit and dynamic stability impacts were also analyzed.

The interconnected Transmission Owner (TO) for this project is American Electric Power. The TO has provided their updated TO analysis results on the lower voltage system based on their own criteria.

This System Impact Study report summarizes both the PJM and TO analysis results for your project.

Note: This updated SIS report does not include any Physical Interconnection Facilities scope or cost estimates from the TO. As this project is in the Expedited Process, a Facilities Study will be conducted by the TO (and any affected Transmission Owner(s)) for updated Physical Interconnection Facilities and System Reinforcement (Network Upgrade) costs. The Facilities Study will be issued to the Project Developers along with the Generator Interconnection Agreement (GIA) as part of the Expedited Process.

The developer has proposed a Solar; Storage generating facility located in the American Electric Power zone — White County, Indiana. The installed facilities will have a total capability of 200.0 MW with 120.0 MW of this output being recognized by PJM as Capacity.

AF2-078 will interconnect with the AEP transmission system via a direct connection to the AF1-207 proposed 345 kV station cut into Olive (AEP) – Reynolds (NIPSCO) 354kV circuit.

To accommodate the interconnection to the AF1-207 proposed 345 kV station, one (1) new 345 kV circuit breaker will be installed. Installation of associated protection and control equipment, line risers, SCADA, jumpers, switches, and 345 kV revenue metering will also be required. AEP reserves the right to specify the final acceptable configuration considering design practices, future expansion, and compliance requirements.

AEP will extend one span of 345 kV transmission line for the generation-leads going to the AF2-078 site. Unless this span extends directly from within the AEP station at the POI to the IC collector station structure, AEP will build and own the first transmission line structure outside of the AF1-207 proposed 345 kV station fence to which the AEP and AF2-078 transmission line conductors will attach.

No violations.

PJM Short Circuit Analysis did not identify any new overduty breakers or >3% contribution to previously identified overduty breakers.

Executive Summary

Generator Interconnection Request AF2-078 is for a 200.0 MW Maximum Facility Output (MFO) solar generation plant. AF2-078 consists of 49 × 3.732 MW SMA SC 4600-UP-US solar PV inverters and 5 x 4.0566 MW Sungrow SC5000-UD BESS inverters with a total capacity of 203.1475 MW. The Point of Interconnection (POI) is at a tap on Reynolds – Olive 345 kV circuit 1 (sharing the POI with AF1-207) in the American Electric Power (AEP) transmission system, White County, Indiana.

AF2-078 was dispatched for stability analysis according to the following scenarios:

       a)       Scenario 1: AF2-078 dispatched at full MFO injection at the POI with PV MW contribution maxed out, and no MW contribution from BESS.

       b)       Scenario 2: AF2-078 dispatched at full MFO injection at the POI with BESS MW contribution maxed out, and reduced PV MW injection.

       c)       Scenario 3: AF2-078 dispatched at full MFO injection at the POI with PV and BESS MW contribution proportional to their capacity.

       d)       Scenario 4: AF2-078 dispatched to full capacity with PV and BESS MW injection maxed out.

This report describes a dynamic simulation analysis of AF2-078 for dispatch Scenario 3 as part of the overall system impact study.

The load flow scenario for the analysis was based on the RTEP 2023 peak load case, modified to include applicable queue projects. AF2-078 has been dispatched online at maximum power output, with 1.0 p.u. voltage at the generator bus.

AF2-078 was tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 72 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady state operation (20 second);

       a)       Three-phase faults with normal clearing time; (and with unsuccessful high-speed reclosing);

       b)       Single-phase faults with stuck breaker;

       b)       Three-phase faults with loss of multiple-circuit tower line; (and with unsuccessful high-speed reclosing).

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 2023 peak load case:

       a)       AF2-078 was able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with AF2-078 included is transiently stable.

       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.

The reactive power capability of AF2-078 meets the 0.95 lagging and leading PF requirement at the high side of the main transformer.

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away of AF2-078.The CSCR results are summarized in Table 7 through Table 10 revealed a minimum CSCR value of 2.52 for P1.06, P1.14, P4.21, P4.22, P4.34 and P7.11, and a maximum CSCR value of 6.68 for P1.01.

The IPCMD and IQCMD states in the REGCAU model of AF2-078 showed erratic behavior for some contingencies in which AF2-078 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, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

The rotor angle of Cook Unit 1 did not achieve a flat response within the 20 second simulation window for several contingencies. This issue did not cause instability in the system. The selected contingencies were run for 30 seconds, and the rotor angles of Cook Unit 1 achieved a flat response at the end of the 30 second simulation time period for most of the contingencies. The same issue was observed in the AF1-046 dynamic analysis; therefore, this response was not caused by the addition of AF2-078. No mitigation is required due to instability.

No mitigations were found to be required.

The reactive power capability of AF2-078 meets the 0.95 lagging and leading PF requirement at the high side of the main transformer.

Steady State Voltage analysis is not required for this queue project at this time.

The Projects below are listed in one or more dispatch for the overloads identified in your report. These projects contribute to the loading of the overloaded facilities identified in your report. The percent overload of a facility and cost allocation you may have towards a particular reinforcement could vary depending on the action of these earlier projects. The status of each project at the time of the analysis is presented in the table. This list may change if any earlier projects withdraw. This table is valid for load flow analyses only.

Midcontinent Independent System Operator (MISO) Preliminary Results - No Impacts
New York Independent System Operator (NYISO) Not required
Tennessee Valley Authority (TVA) Not required
Louisville Gas & Electric (LG&E) Not required
Duke Progress Energy (DUKE) Not required
Carolina Power & Light East (CPLE) Not required
Carolina Power & Light West (CPLW) Not required

The AF2-078 project may be responsible for a contribution to the following estimated System Reinforcement (Network Upgrade) costs as shown below. The Network Upgrades listed below are required to alleviate a reliability criteria violation identified in the Network Impact analysis that PJM has performed for this System Impact Study. No physical Interconnection Facilities costs are included in this cost table.

Note 1: PJM Open Access Transmission Tariff (OATT) Part VI, section 217.3A outlines cost allocation rules for the Expedited Process projects. These rules are further clarified in PJM Manual 14A, Attachment B.

Note 2: To Project Developers with System Reinforcements listed: If your present cost allocation to a System Reinforcement indicates $0, then please be aware that if a prior project in the Expedited Process withdraws from the cycle, the cost responsibilities can change and a cost allocation may be assigned to your project. In addition, although the cost allocation to a System Reinforcement is presently $0, your project may need this system reinforcement completed to be deliverable to the PJM system. If your project desires to possibly come into service prior to completion of the system reinforcement, you would need to request an interim deliverability study to determine if all or a portion of your project would be deliverable.

The one line included in this refreshed System Impact Study report was originally developed prior to the Transition Date. Therefore, not all verbiage on the one line may align with the current Tariff definitions. An updated one line diagram will be provided in the Facilities Study report for the Expedited Process projects.

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