This Final System Impact Study (SIS) Report has been prepared in accordance with the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 314 for New Service Requests (projects) in Transition Cycle 1 (TC1). The Project Developer/Eligible Customer (developer) is Wild Rose Solar Project, LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Appalachian Power Company.

The Final System Impact Study is conducted on an aggregate basis within a New Services Request’s Cycle, and results are provided in both (i) a single Cycle summary format and (ii) an individual project-level basis. The Final System Impact Study Results (for both the summary and individual reports) will be publicly available on PJM’s website. Project Developers must obtain the results from the website.

In accordance with PJM Manual 14H, section 5, Final Agreement Negotiation Phase, the purpose of the Final Agreement Negotiation Phase is to:

1. Negotiate, execute and enter into the applicable final interconnection related service agreement found in Tariff, Part IX;
2. Conduct any remaining analyses or updated analyses based on New Service Requests withdrawn during Decision Point III (DP3); and
3. Adjust the security obligation based on New Service Requests withdrawn during Decision Point III and/or during the Final Agreement Negotiation Phase.

Retool 1:

In accordance with PJM Tariff Part VII.D 314 B(1)(a), Final Agreement Negotiation Phase:

• PJM will perform a retool (Retool 1) after the conclusion of DP3 considering only the projects moving on in the Final Agreement Negotiation Phase (Removes DP3 withdrawals).
• The Final System Impact Study reflecting results from the retooled analysis (Retool 1) will be publicly available on PJM’s website; Project Developers and Eligible Customers must obtain the results from the website.
• PJM will provide updated final electronic agreements to Project Developers and Eligible Customers in the Cycle reflecting updates from the Final System Impact Study after Retool 1 including the adjusted Security requirements.

The AG1-124 Final System Impact Study (Retool 1) Report is available for download here.

Retool 2 (if needed):

If particular New Service Requests do not sign their final agreements after receiving the updated information after Retool 1, there may be the need to run a second retool (Retool 2) to identify if any network upgrades are no longer necessary:

• PJM will perform Retool 2 (if necessary) considering only the removal of projects from the model which chose not to execute their agreements after Retool 1.
• The updated Final System Impact Study reflecting results from Retool 2 will be publicly available on PJM’s website; Project Developers and Eligible Customers must obtain the results from the website.
• If there are any adjustments to the agreements required after Retool 2, the necessary network upgrade or Security changes will be handled via the scope change process post-GIA.

The Project Developer has proposed a Solar generating facility located in the Appalachian Power Company zone — Nelson County, Virginia. The installed facilities will have a total capability of 90.0 MW with 53.01 MW of this output being recognized by PJM as Capacity.

Physical Interconnection Facility Study

The transmission owner has completed the Physical Interconnection Facilities Study. This report is available for download.

AG1-124 will interconnect on the AEP Appalachian Power Company transmission system via a newly constructed 138 kV station tapping the Riverville - Gladstone 138 kV line.

The table below shows a summary of the total cost estimates for this New Service Request project. The Facilities Studies for the Transmission Owner Interconnection Facilities (TOIF) and Physical Interconnection Network Upgrades were performed by the Transmission Owner in Phase II. Facilities Studies are available for download on PJM.com (see General Section for document links). The Interconnected Transmission Owner has performed a Facilities Study for the required System Reliability Network Upgrades in Phase III (see System Reinforcement Section for document links).

Based on the Final SIS results, the AG1-124 project has the following allocation of costs for interconnection. The Security amount required after the Final SIS and revised agreements is also shown below.

* Contributes to calculation for Security. See Security Requirement Section of this report for additional detail.

** This value reflects the results at the time of the report posting and it is subject to change. AFS – Non-PJM Violations are not subject to Security. For latest AFS – Non-PJM Violations, please refer to the latest Affected System Study Report for your project.

Definitions

Transmission Owner Interconnection Facilities: Facilities that are owned, controlled, operated and maintained by the Transmission Owner on the Transmission Owner’s side of the Point of Change of Ownership to the Point of Interconnection, including any modifications, additions or upgrades made to such facilities and equipment, that are necessary to physically and electrically interconnect the Generating Facility with the Transmission System or interconnected distribution facilities.

Stand Alone Network Upgrades: Network Upgrades, which are not part of an Affected System, which a Project Developer may construct without affecting day-to-day operations (e.g. taking a transmission outage) of the Transmission System during their construction.

Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider’s overall Transmission System for the general benefit of all users of such Transmission System. Network Upgrades have no impact or potential impact on the Transmission System until the final tie-in is complete.

Notes

Note 1: PJM Open Access Transmission Tariff (OATT), Part VII, Subpart D, section 307.5 outlines cost allocation rules. The rules are further clarified in PJM Manual 14H, section 4.2.6. PJM shall identify the New Service Requests in the Cycle contributing to the need for the required Network Upgrades within the Cycle. All New Service Requests that contribute to the need for a Network Upgrade will receive cost allocation for that upgrade pursuant to each New Service Request’s contribution to the reliability violation identified on the transmission system in accordance with PJM Manuals.

Note 2: There will be no inter-Cycle cost allocation for Interconnection Facilities or Network Upgrades identified in the System Impact Study costs identified in a Cycle; all such costs shall be allocated to New Service Requests in that Cycle.

Note 3: For Project Developers with System Reinforcements listed: If this project presents cost allocation to a System Reinforcement indicates $0, then please be aware that as changes to the interconnection process occur, the cost responsibilities can change and a cost allocation may be assigned to this project. In addition, although this project presents cost allocation to a System Reinforcement is presently $0, this project may need this system reinforcement completed to be deliverable to the PJM system. If this project desires to come into service prior to completion of the system reinforcement, the Project Developer will need to request PJM to perform an interim deliverability study to determine if they would be deliverable for all or a portion of their output for each delivery year until the system reinforcement is complete.

Per Tariff Part VII, Subpart D, section 314 (Final Agreement Negotiation Phase) A.1 and PJM Manual 14H, Section 5, if a Transition Cycle 1 New Service Request is withdrawn during Decision Point III and/or the Final Agreement Negotiation Phase, PJM shall remove the New Service Request from the Cycle and adjust the Security obligations of other New Service Requests based on the withdrawal. The Final System Impact Study results will reflect the updated Security amount for this project. Security may be in the form of cash, letter of credit, or other form of Security acceptable to PJM (see PJM M14H, Section 6.4).

Security is calculated for a New Service Request based on the Network Upgrade costs allocated pursuant to the Final System Impact Study results.

Note 1: "Network Upgrades" referred to in the calculation include both (i) the Physical Interconnection Network Upgrades and (ii) the System Reliability Network Upgrades as shown in the Cost Summary table.

Security Due for AG1-124

Security has been calculated for the AG1-124 project(s) based on the Final System Impact Study results and is shown in the table below. This Security must be provided at Final SIS through either a wire transfer or letter of credit or other form of Security deemed acceptable by PJM per Manual 14H, Section 6.4.

AG1-124 will interconnect with the AEP transmission system via a new station cut into the Riverville - Gladstone 138 kV Circuit. The estimates provided in this report are preliminary in nature, as they were determined without the benefit of detailed engineering studies. Final estimates will require an on-site review and coordination to determine final construction requirements.

The total preliminary cost estimate for the Transmission Owner scope of work (including TOIF and Physical Interconnection Network Upgrades) is given in the table below. These costs do not include CIAC Tax Gross-up.

Transmission Owner Scope

Based on the scope of work for the Interconnection Facilities, it is expected to take 26 month(s) after the signing of a Generator Interconnection Agreement (as this is a FERC connection) and construction kickoff call to complete the installation of the physical connection work. This assumes that there will be no environmental issues with any of the new properties associated with this project, that there will be no delays in acquiring the necessary permits for implementing the defined interconnection work, and that all system outages will be allowed when requested.

Note that the TO findings were made from a conceptual review of this project. A more detailed review of the connection facilities and their cost will be identified in a future study phase. Further note that the cost estimate data provided should be considered high level estimates since it was produced without a detailed engineering review. The Project Developer will be responsible for the actual cost of construction. TO herein reserves the right to return to any issues in this document and, upon appropriate justification, request additional monies to complete any reinforcements to the transmission systems.

Remote Terminal Work: During Phase II of the PJM interconnection process, TO’s System Protection Engineering Department will review transmission line protection as well as anti-islanding required to accommodate the new generation and interconnection substation. System Protection Engineering will determine the minimal acceptable protection requirements to reliably interconnect the proposed generating facility with the transmission system. The review is based on maintaining system reliability by reviewing TO’s protection requirements with the known transmission system configuration which includes generating facilities in the area. This review may determine that transmission line protection and communication upgrades are required at remote substations.

No Transmission Owner impacts identified.

The developer is responsible for all design and construction related activities on the developer’s side of the Point of Change in Ownership. AEP interconnection requirements can be found here.

To the extent that these Applicable Technical Requirements and Standards may conflict with the terms and conditions of the Tariff, the Tariff shall control.

The developer will be required to install equipment necessary to provide Revenue Metering (KWH, KVARH) and real time data (KW, KVAR) for their generating Resource. See PJM Manual 01, PJM Manual 14D, and PJM Tariff Part IX, Subpart B, Appendix 2, section 8.

The solar generation facility shall provide the Transmission Provider with site-specific meteorological data including:

• Temperature (degrees Fahrenheit)
• Atmospheric Pressure (hectopascals)
• Irradiance
• Forced outage data

The Project Developer will be required to comply with all interconnected Transmission Owner’s revenue metering requirements located at the following link: PJM - Transmission Owner Engineering & Construction Standards.

Based on PJM’s Short Circuit Analysis, this project did not contribute >1% fault duty to previously identified overdutied breakers, nor did it cause any new overdutied breakers.

Analysis Complete - No Issues

Executive Summary

New Service Requests AG1-124 and AG1-494 in PJM Transition Cycle 1, Cluster 54 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 54 projects.

This analysis is effectively a screening study to determine whether the addition of the cluster 54 projects will meet the dynamics requirements of the NERC, AEP 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 54 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 54 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 111 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

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

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

       b)       Single-phase bus faults with normal clearing time,

       c)       Single-phase faults with stuck breaker,

       d)       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,

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

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:

       a)       Cluster 54 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 54 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.

       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.

AG1-124 and AG1-494 meet the 0.95 leading and lagging PF requirement.

The composite short-circuit ratio (CSCR) assessment was performed forinverter-based renewable generation units which are within one (1) substation away AG1-124 and AG1-494. CSCR results are summarized in Table 4 to Table 9 and revealed a minimum and maximum CSCR values of 3.99 for P1.16 and 6.08 for P4.21 & P4.22, respectively.

High voltage spikes occurred in the simulations immediately after fault clearing for some 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.” 

The IPCMD and IQCMD states in the REGCA1 model of AG1-494 GEN, and AG1-124 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.

Non-queue project AE1-108:

In the previous phase (phase 2) of the dynamic simulation analysis for Cluster 54, the relay pick-up time of AE1-108, instance 93882501 (VTGTPAT) was adjusted to 0.25 seconds to prevent tripping under one contingency. For this phase of the study (phase 3) the relay pick-up time for 93882501 (VTGTPAT) of AE1-108 was restored to original setting 0.0 seconds. No trippings of this unit were observed in this study.

No mitigations were found to be required.

Table 1: TC1 Cluster 54 Projects

The reactive power capability of AG1-124 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer.

Steady State Voltage Analysis is Not Required.

The New Service Requests below are listed in one or more dispatch for the overloads identified in this report. These projects contribute to the loading of the overloaded facilities identified in this report. The percent overload of a facility and cost allocation you may have towards a particular reinforcement could vary depending on the action of other projects. The status of each project at the time of the analysis is presented in the table. This list may change as other projects withdraw or modify their requests. This table is valid for load flow analyses only.

As part of PJM's analysis, PJM evaluated the potential impacts on tie line facilities between PJM and an affected system entity, which were identified per PJM planning analysis criteria. This upgrade may be required on the affected system portion of the tie line along with cost allocation of such upgrade if applicable, in coordination with the affected system. Depending on the affected system, this project may not be contingent on upgrade based on PJM planning analysis criteria, but may be contingent on this upgrade based on the Affected System Operator's planning criteria, provided in the Affected Systems Study Section, herein.

In coordination with other Affected System Operators, PJM has determined that the Affected System Operator for this project that requires an Affected System Study. For the latest Affected System Study results pertaining this project, please refer to your Affected System Study report by the Affected System Operator. If the Affected System Operator identified the need for a system reinforcement on their system due to their planning criteria, Project Developer must follow the Affected System Operator Tariff for construction of the network upgrade. PJM lists any required network upgrades identified by the Affected System Operator in the PJM Project Developer’s GIA under Schedule F.

Based on the Final System Impact Study analysis results, this project is contingent on and may have cost responsibility for the following System Reinforcements:

PJM evaluated the impact of topology changing reinforcements to mitigate the impacts driven by New Service Requests. PJM determined which reinforcements were eliminated as a result of modeling the topology changing reinforcements. PJM then grouped the topology changing and eliminated reinforcements by region and computed a discount factor to apply to reinforcements to reduce the cost of all these reinforcements down to the cost of contstructing only the topology changing reinforcements. For additional details, please click the icon below

Shown below are the details of the cost allocated, contingent, eliminated, topology and potential aggregate contributor reinforcements for this project. Please refer to the System Reinforcement table above and the information below for more detail.

AG1-124 One Line Diagram