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 Liberty Madison Storage LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is AEP Indiana Michigan Transmission Company, Inc..

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 Conduct any remaining analyses or updated analyses based on New Service Requests withdrawn during Decision Point III (DP3); and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 Adjust the security obligation based on New Service Requests withdrawn during Decision Point III and/or during the Final Agreement Negotiation Phase.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 TC1 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.

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 TC1 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 Storage facility located in the AEP Indiana Michigan Transmission Company, Inc. zone — Madison County, Indiana. The installed facilities will have a total capability of 300.0 MW with 300.0 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.

AF2-407 will interconnect on the AEP Indiana Michigan Transmission Company, Inc. transmission system at the Fall Creek 345 kV substation.

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 AF2-407 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 Section of this report for additional detail.

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 AF2-407

Security has been calculated for the AF2-407 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.

AF2-407 will interconnect with the AEP transmission system via a direct connection to the Fall Creek 345 kV Station. 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 30 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 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 (projects) in PJM Transition Cycle 1, Cluster 62 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 62 projects.

This analysis is effectively a screening study to determine whether the addition of the cluster 62 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 62 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.

Cluster 62 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 199 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)       Three-phase faults with loss of multiple-circuit tower line; (and with unsuccessful high-speed reclosing).

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the AEP 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:

       a)       Cluster 62 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b)       The system with Cluster 62 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.

AF2-173, AF2-177, AF2-407, AG1-367 and AG1-375 meet the 0.95 leading and lagging PF requirement.

AF2-173 exhibited slow reactive power recovery for several contingencies. Although this issue did not cause instability in the system, the model was tuned to achieve faster reactive power output settlement. This was accomplished by adjusting the Ki parameters in the plant controller (REPCA1) for AF2-173, setting Ki to 0.15 from its original value of 0.5.

AF2-177 exhibited slow reactive power recovery for several contingencies. Although this issue did not cause instability in the system, the model was tuned to achieve faster reactive power output settlement. This was accomplished by adjusting the Ki parameters in the plant controller (REPCA1) for AF2-177, setting Ki to 0.15 from its original value of 0.5.

AG1-367 exhibited slow reactive power recovery for several contingencies. Although this issue did not cause instability in the system, the model was tuned to achieve faster reactive power output settlement. This was accomplished by adjusting the Kc parameters in the plant controller (REPCA1) for AG1-367, setting Kc to 0.1 from its original value of 0.

AG1-375 exhibited slow reactive power recovery for several contingencies. Although this issue did not cause instability in the system, the model was tuned to achieve faster reactive power output settlement. This was accomplished by adjusting the Kc parameters in the plant controller (REPCA1) for AG1-375, setting Kc to 0.1 from its original value of 0.

AF2-407 exhibited slow reactive power recovery for several contingencies. Although this issue did not cause instability in the system, the model was tuned to achieve faster reactive power output settlement. This was accomplished by adjusting the Kc, Ki and Kp parameters in the plant controller (REPCA1) for AF2-407, setting Kc to 0.15 from its original value of 0.04, setting Ki to 2 from its original value of 0.5, and setting Kp to 0.5 from its original value of 0.

Fictitious frequency response at AF2-407 generator bus tripped the queue project due to the action of instantaneous under-frequency and over-frequency relays when faults were applied at Fall Creek 345 kV (AF2-407 POI). Therefore, the relay pickup times for frequency relay instances 96116513 and 96116516 were set to 20 seconds to avoid fictitious frequency tripping of the unit.

A sensitivity analysis was conducted to evaluate the dynamic performance of the system following the addition of a new 345/765 kV transformer at the Jefferson substation and a new 345 kV circuit between the Jefferson and Clifty substations. The integration of the transformer did not introduce any system instability.

No mitigations were found to be required.

Table 1: TC1 Cluster 62 Projects

The reactive power capability of AF2-407 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer.

Steady State Voltage Analysis complete, no voltage issues found.

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 accordance with PJM Tariff Part VII, Subpart D, section 312.A.1.b and as outlined in PJM Manual 14H, Section 13, in Phase III of the Cycle, PJM coordinates with the Affected System Operators to conduct any studies required to determine the impact of the New Service Request on any Affected System and will include the Affected System Study results in Phase III System Impact Study, if available from the Affected System Operator.

If your project required an Affected System Study, the results are shown below from the Affected System Operator.

For more details, 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 will list any required network upgrades identified by the Affected System Operator in the PJM Project Developer’s GIA under Schedule F.

Replace 0.17 miles of 795 MCM 26X7 ACSR conductor
and 1.97 miles of 954 MCM 45X7 ACSR in the Hardin
Co-Central Hardin 138kV line with conductor
capable of 418 MVA 60F emergency rating or better.
Reset the loadability relays at Hardin Co
associated with the Hardin Co-Central Hardin 138kV
line to a minimum of 2625 amps.

Increase the maximum operating temperature to 212F
Of the 0.51 miles of 397.5 MCM 26X7 ACSR in the
Bardstown Industrial Tap-East Bardstown 69kV line.

Reconductor 1.37 miles of 397.5 MCM 26X7 ACSR in
the Bardstown- Bardstown Industrial Tap 69kV line
with a minimum of 556.5 MCM 26x7 ACSR. Replace the
397.5 MCM 26X7 ACSR jumper at Bardstown Industrial
Tap with a minimum of 556.5 MCM 26x7 ACSR.

Increase the maximum operating temperature to 165F
of the 2.53 miles of 397.5 MCM 26X7 ACSR in the
Hodgenville 774-Hodgenville EKPC 69kV line.

Increase the maximum operating temperature to 145F
of the 8.1 miles of 3/0 6x1 ACSR in the
Millersburg-Paris 12 69kV line.

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.

AF2-407 One Line Diagram