AG1-125 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 AG1-125 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 generating facility located in the American Electric Power zone — Madison County, Ohio. The installed facilities will have a total capability of 400.0 MW with 234.9 MW of this output being recognized by PJM as Capacity.

AG1-125 will interconnect on the AEP transmission system tapping the Marysville to Flatlick 765 kV line.

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 AG1-125 is for a 400 MW Maximum Facility Output (MFO) solar generation plant. AG1-125 consists of 142 × Sungrow SG3150U solar PV inverters rated at 2.8631 MW each. AG1-125 has a Point of Interconnection (POI) at a tap on Marysville – Flatlick 765 kV circuit in the American Electric Power (AEP) transmission system, Madison County, Ohio. 

Generator Interconnection Request AG1-126 is for a 400 MW Maximum Facility Output (MFO) solar generation plant. AG1-126 consists of 142 × Sungrow SG3150U solar PV inverters rated at 2.8696 MW each. AG1-126 has a Point of Interconnection (POI) at a tap on Marysville – Flatlick 765 kV circuit in the American Electric Power (AEP) transmission system, Madison County, Ohio. 

This report describes a dynamic simulation analysis of AG1-125 & AG1-126 as part of the overall system impact study.

The load flow scenario for the analysis was based on the RTEP 2024 peak load case, modified to include applicable queue projects. AG1-125 & AG1-126 have been dispatched online at maximum power output, with 1.0 p.u. voltage at the generator bus.

AG1-125 & AG1-126 were tested for compliance with NERC, PJM, Transmission Owner, and other applicable criteria. Steady-state condition and 31 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 and, when applicable, with unsuccessful high-speed reclosing;

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

       d)       Single-phase faults with stuck breaker;

No relevant three-phase faults with loss of multiple-circuit tower line were identified for this study.

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

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 2024 peak load case:

       a)       AG1-125 & AG1-126 were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with AG1-125 & AG1-126 included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and local modes.

       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 AG1-125/AG1-126 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 AG1-125 and AG1-126. The CSCR assessment revealed a minimum and maximum CSCR values of 4.047 for P1.02 & P1.04 and 4.415 for P0.01, respectively.

The initial results of both AG1-125 and AG1-126, showed slow reactive power recovery and terminal voltages out of limits for multiple contingencies and active power not returning to pre-fault values for some contingencies. All these issues were resolved by adjusting the parameters of the plant controller module of both queue projects.

The IPCMD and IQCMD states in the REGCA1 model of AG1-125 and AG1-126 showed erratic behavior for some contingencies in which AG1-125 and AG1-126 had 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.

The reactive power capability of AG1-125/AG1-126 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 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.

The AG1-125 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.

An updated one line diagram will be provided in the Facilities Study report for the Expedited Process projects.

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