AF2-407 Phase III Study Report
v1.00 released 2025-09-18 16:46
Fall Creek 345 kV
300.0 MW Capacity / 300.0 MW Energy
Introduction
This Phase III System Impact Study Report (PH3) has been prepared in accordance with the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 312 for New Service Requests (projects) in Transition Cycle 1. 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..
Preface
New Service Requests meeting the requirements of Tariff, Part VII, Subpart D, Decision Point II, were included in the Phase III System Impact Study. The Phase III 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 executive summary format and (ii) an individual project-level basis. The Phase III System Impact Study Results (for both the executive summary and individual reports) will be publicly available on PJM’s website. Developers must obtain the results from the website.
In accordance with PJM Manual 14H, section 4.7, PJM takes the following actions during the Phase III System Impact Study:
- PJM will retool load flow, short circuit and stability results based on decisions made by Project Developers or Eligible Customers during Decision Point II.
- PJM will coordinate with Affected System Operators to conduct any studies required to determine the final impact of a New Service Request on any Affected System and will include the final Affected System Study results in the Phase III System Impact Study, if available from the Affected System.
- The Phase III System Impact Study Results will be publicly available on PJM’s website; Project Developers and Eligible Customers must obtain the results from the website.
- PJM will tender draft final agreements to Project Developers or Eligible Customers.
The Transmission Owner takes the following actions during the Phase III System Impact Study:
- Verify Interconnection Facilities and Network Upgrades required to accommodate the New Service Request.
- Perform a Facilities Study. The Facilities Study in Phase III System Impact Study phase will be for the System Reliability Network Upgrades. The Facilities Study requirements are outlined in Attachment C of PJM Manual 14H. The study will be conducted pursuant to Tariff, Part VII, Subpart D, section 307(A)(7).
Decision Point III Requirements
At the close of Phase III System Impact Study, PJM will initiate Decision Point III (DP3). During DP3, the Project Developer will have 30 days to decide whether to proceed with their project. If the Project Developer elects to proceed, they should provide the elements defined in the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 313.A. Additional information on these elements is available in PJM Manual 14H sections 4.8, 6, and 7.
As stated in PJM Tariff, Part VII, Subpart D, section 313.C, New Service Requests may not be changed or modified in any way for any reason during Decision Point III. A New Service Request must be withdrawn and resubmitted in a subsequent Cycle to the extent a Project Developer or Eligible Customer wants to make any changes to such New Service Request at this point in the Cycle process.
Adverse Test Eligibility
This New Service Request does not meet the Adverse Study Impact Criteria and has the option to either move forward in the Cycle process or withdraw at DP3 with cumulative Readiness Deposits forfeited. See adverse study impact calculation below.
This section details whether a Project Developer or Eligible Customer qualifies for the Adverse Study Impact clause outlined in the PJM OATT, Part VII, Subpart D, section 313.B and Manual 14H, section 6.2.2. In order to qualify for an Adverse Study Impact at Decision Point III, the Network Upgrade cost from Phase II to Phase III must:
- Increase overall by 35% or more
- Increases by more than $25,000 per MW (Includes Costs identified in Affected System studies)
If a New Service Request meets the criteria above and chooses to withdraw the request, PJM will refund the cumulative Readiness Deposit amounts paid at the Application Phase, Decision Point I, and Decision Point II (RD1, and RD2 and RD3, respectively).
The below calculations show the computation of this New Service Request's Adverse Study Impact
General
The Project Developer has proposed a Storage facility located in the American Electric Power 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.
Project Information
- New Service Request Number:
- AF2-407
- Project Name:
- Fall Creek 345 kV
- Project Developer Name:
- Liberty Madison Storage LLC
- State:
- Indiana
- County:
- Madison
- Transmission Owner:
- AEP Indiana Michigan Transmission Company, Inc.
- MFO:
- 300.0
- MWE:
- 300.0
- MWC:
- 300.0
- Battery Storage Specification:
- 3000.0 MWh, 10.0-hr class
- Grid Charging:
- Yes
- Fuel Type:
- Storage
- Basecase Study Year:
- 2027
Physical Interconnection Facility Study
The transmission owner has completed the Physical Interconnection Facilities Study. This report is available for download.
Point of Interconnection
AF2-407 will interconnect on the AEP Indiana Michigan Transmission Company, Inc. transmission system at the Fall Creek 345 kV substation.
Cost Summary
The table below shows a summary of the total cost estimates for this New Service Request project. In Phase III SIS, the interconnected Transmission Owner has performed a facilities study for the required System Reliability Network Upgrades. The Facilities Studies for the Transmission Owner Interconnection Facilities (TOIF) and Physical Interconnection Network Upgrades were performed by the Transmission Owner in Phase II and are available for download on PJM.com (see General Section for document links).
Based on the Phase III SIS results, the AF2-407 project has the following allocation of costs for interconnection. The Security amount required at DP3 is also shown below.
| Description | Cost Allocated to AF2-407 | Cost Subject to Security |
|---|---|---|
| Transmission Owner Interconnection Facilities (TOIF) | $2,435,538 | $2,435,538 |
| Other Scope | $0 | $0 |
| Option to Build Oversight | $0 | $0 |
| Physical Interconnection Network Upgrades | ||
| Stand Alone Network Upgrades | $0 | $0 |
| Network Upgrades | $3,325,190 | $3,325,190 |
| System Reliability Network Upgrades | ||
| Steady State Thermal & Voltage (SP & LL) | $4,519,578 | $4,519,578 |
| Transient Stability | $0 | $0 |
| Short Circuit | $0 | $0 |
| Transmission Owner Analysis | ||
| SubRegional | $0 | $0 |
| Distribution | $0 | $0 |
| Affected System Study Reinforcements | ||
| AFS - PJM Violatons | $498,894 | $0 |
| AFS - Non-PJM Violations | $235,944 | $0 |
| Total | $11,015,144 | $10,280,306 |
* 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, such as other projects withdrawing, reducing in size, etc, 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.
Security Requirement
Per Tariff Part VII, Subpart D, section 313 (Decision Point III) A.1.a and PJM Manual 14H, section 8.6.1, Project Developers and Eligible Customers are required to provide Security in a form acceptable to PJM at Decision Point III which runs concurrently with the projects' Final Agreement Negotiation Phase. 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 Phase III 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 Phase III System Impact Study results and is shown in the table below. This Security must be provided at Decision Point III through either a wire transfer or letter of credit or other form of Security deemed acceptable by PJM per Manual 14H, Section 6.4.
Security Due for AF2-407
Transmission Owner Scope of Work
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.
| Network Upgrades | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| n9548.0 |
Fall Creek 345 kV Substation: Expansion. • Extend the Fall Creek 345 kV Substation west Bus #1 to the south. • Extend the existing partial “M” circuit breaker string to the new west Bus #1 extension. • Install two (2) new 345 kV 5000A 63 kA circuit breakers and associated control relaying. • Install four (4) new breaker disconnect switches. • Install associated and additional buswork, bus supports, jumpers, insulators, grounding, SCADA (Supervisory Control and Data Acquisition) connectivity, fiber-optic relaying connectivity & equipment, and foundations. • Review and revise the protective relay settings for the remainder of the Fall Creek 345 kV Substation to account for the addition of the new circuit breakers and the proposed AF2-407 generation source. • Coordinate line protection settings with Duke Energy for the Fall Creek - Noblesville 345 kV Circuit due to the changes required at the Fall Creek 345 kV Substation to interconnect the proposed AF2-407 project. • Coordinate line protection settings with AES Indiana for the Fall Creek - Sunnyside 345 kV Circuit due to the changes required at the Fall Creek 345 kV Substation to interconnect the proposed AF2-407 project. |
$1,368,018 | $1,516,980 | $208,732 | $231,460 | $3,325,190 | $3,325,190 |
| Transmission Owner Interconnection Facilities | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) |
• Install two (2) new 90 ft. custom steel single pole, single circuit dead end structures on concrete foundations with anchor bolt cages. • Install two (2) spans of aluminum conductor steel-reinforced (ACSR) 2-bundled 954 54/7 (Cardinal) transmission line conductor with 48-count fiber optical ground wire (OPGW) shield wire for the generation lead circuit exiting from the Fall Creek 345 kV Substation. • Install dual direct fiber current differential relays for the protection scheme for the proposed AF2-407 generation lead. • Install a 345 kV revenue metering package, including one (1) control house-installed metering panel with primary and backup meters, three (3) 1-phase current transformers (CTs), three (3) 1-phase capacitor coupled voltage transformers (CCVTs), and associated structures, foundations, grounding, and telecommunications connectivity at the Fall Creek 345 kV Substation for the proposed AF2-407 generation lead circuit. • Extend two (2) fiber-optic cables via underground and transmission-supported all dielectric self supporting (ADSS) with ADSS entrances via diverse paths from the Fall Creek 345 kV Substation control house to fiber demarcation splice boxes. The fiber-optic cable runs will support direct fiber relaying between the Fall Creek 345 kV Substation and the Project Developer's collector station. The Project Developer will be responsible for the fiber extension from the splice boxes to the collector station. |
$1,263,841 | $869,954 | $177,813 | $123,930 | $2,435,538 | $2,435,538 |
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 2 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.
Transmission Owner Analysis
No Transmission Owner impacts identified.
Developer Requirements
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. Refer to AF2-407 Physical Interconnection Facilities Study for additional requirements found in the General Section of the report.
To the extent that these Applicable Technical Requirements and Standards may conflict with the terms and conditions of the Tariff, the Tariff shall control.
Revenue Metering and SCADA Requirements
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.Transmission Owner Requirements
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 and in the Physical Interconnection Facilities Study.
Summer Peak Analysis
The New Service Request was evaluated as a 300.0 MW (300.0 MW Capacity) injection in the AEP area. Project was evaluated for compliance with applicable reliability planning criteria (PJM, NERC, NERC Regional Reliability Councils, and Transmission Owners). Potential summer peak period network impacts were as follows:
Note: The capacity portion of Generation Interconnection Requests are evaluated for single or N-1 contingencies. The full energy output of Generation Interconnection Requests are evaluated for multiple facility contingencies (double circuit tower line, fault with a stuck breaker, and bus fault).
The following flowgates remain after considering the topology reinforcements required by the cycle.
| Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution |
|---|---|---|---|---|---|---|---|---|---|
| OVEC |
06DEARB1-06PIERCE 345.0 kV Ckt 1 line
248001 to 248013 ckt 1 |
DEOK_P2-3_1403_MIAMI FORT_SRT-A
CONTINGENCY 'DEOK_P2-3_1403_MIAMI FORT_SRT-A' OPEN BRANCH FROM BUS 249567 TO BUS 243233 CKT 1 /*08M.FORT 345.0 - 05TANNER 345.0 OPEN BRANCH FROM BUS 249567 TO BUS 251950 CKT 7 /*08M.FORT 345.0 - 08M.FRT7 22.0 END |
Breaker | AC | 111.15 % | 971.0 | B | 1079.31 | 24.08 |
| OVEC |
06DEARB1-06PIERCE 345.0 kV Ckt 1 line
248001 to 248013 ckt 1 |
DEOK_P2-3_1401_MIAMI FORT_SRT-A
CONTINGENCY 'DEOK_P2-3_1401_MIAMI FORT_SRT-A' OPEN BRANCH FROM BUS 249567 TO BUS 243233 CKT 1 /*08M.FORT 345.0 - 05TANNER 345.0 OPEN BRANCH FROM BUS 249567 TO BUS 250057 CKT 9 /*08M.FORT 345.0 - 08M.FORT 138.0 END |
Breaker | AC | 110.64 % | 971.0 | B | 1074.33 | 24.08 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
(No impacts were found for this analysis)
Summer Potential Congestion due to Local Energy Deliverability
PJM also studied the delivery of the energy portion of this interconnection request. Any problems identified below are likely to result in operational restrictions to the project under study. The developer can proceed with network upgrades to eliminate the operational restriction at their discretion by submitting an Upgrade Request into the New Service Request process.
Note: Only the most severely overloaded conditions are listed below. There is no guarantee of full delivery of energy for this project by fixing only the conditions listed in this section. With an Upgrade Request, a subsequent analysis will be performed which shall study all overload conditions associated with the overloaded element(s) identified.
The following flowgates remain after considering the topology reinforcements required by the cycle.
| Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution |
|---|---|---|---|---|---|---|---|---|---|
| AEP |
AF1-119 TP-05KEYSTN 345.0 kV Ckt 1 line
944540 to 243225 ckt 1 |
AEP_P1-2_#8702_2543_SRT-A-C
CONTINGENCY 'AEP_P1-2_#8702_2543_SRT-A-C' OPEN BRANCH FROM BUS 944530 TO BUS 243232 CKT 2 /*AF1-118 TP 345.0 - 05SORENS 345.0 END |
OP | AC | 131.92 % | 897.0 | B | 1183.36 | 45.27 |
| AEP |
AF2-177 TP-AF1-118 TP 345.0 kV Ckt 2 line
958860 to 944530 ckt 2 |
AEP_P1-2_#4817_6341_SRT-A
CONTINGENCY 'AEP_P1-2_#4817_6341_SRT-A' OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 /*05KEYSTN 345.0 - 05SORENS 345.0 END |
OP | AC | 113.9 % | 971.0 | B | 1105.94 | 45.5 |
| AEP |
05KEYSTN-05SORENS 345.0 kV Ckt 1 line
243225 to 243232 ckt 1 |
Base Case | OP | AC | 108.31 % | 897.0 | A | 971.56 | 32.86 |
| AEP |
AF1-202 TP-AF1-119 TP 345.0 kV Ckt 1 line
945370 to 944540 ckt 1 |
AEP_P1-2_#8702_2543_SRT-A-C
CONTINGENCY 'AEP_P1-2_#8702_2543_SRT-A-C' OPEN BRANCH FROM BUS 944530 TO BUS 243232 CKT 2 /*AF1-118 TP 345.0 - 05SORENS 345.0 END |
OP | AC | 103.54 % | 897.0 | B | 928.73 | 45.27 |
| AEP |
05KEYSTN-05SORENS 345.0 kV Ckt 1 line
243225 to 243232 ckt 1 |
AEP_P1-2_#8702_2543_SRT-A-C
CONTINGENCY 'AEP_P1-2_#8702_2543_SRT-A-C' OPEN BRANCH FROM BUS 944530 TO BUS 243232 CKT 2 /*AF1-118 TP 345.0 - 05SORENS 345.0 END |
OP | AC | 103.3 % | 1318.0 | B | 1361.46 | 44.91 |
| AEP |
05DESOTO-AF2-177 TP 345.0 kV Ckt 2 line
243218 to 958860 ckt 2 |
AEP_P1-2_#4817_6341_SRT-A
CONTINGENCY 'AEP_P1-2_#4817_6341_SRT-A' OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 /*05KEYSTN 345.0 - 05SORENS 345.0 END |
OP | AC | 100.27 % | 971.0 | B | 973.65 | 45.5 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
| Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution |
|---|---|---|---|---|---|---|---|---|---|
| AEP |
AF1-118 TP-05SORENS 345.0 kV Ckt 2 line
944530 to 243232 ckt 2 |
AEP_P1-2_#4817_6341_SRT-A
CONTINGENCY 'AEP_P1-2_#4817_6341_SRT-A' OPEN BRANCH FROM BUS 243225 TO BUS 243232 CKT 1 /*05KEYSTN 345.0 - 05SORENS 345.0 END |
OP | AC | 100.62 % | 1318.0 | B | 1326.14 | 45.77 |
Winter Peak Analysis
PJM will start performing Winter Peak analysis in Transition Cycle 2.
Winter Potential Congestion due to Local Energy Deliverability
PJM will start performing Winter Peak analysis in Transition Cycle 2.
Light Load Analysis
The New Service Request was evaluated as a 300.0 MW injection and 300.0 MW withdrawal in the AEP area. Project was evaluated for compliance with applicable reliability planning criteria (PJM, NERC, NERC Regional Reliability Councils, and Transmission Owners). Potential light load period network impacts were as follows:
The following flowgates remain after considering the topology reinforcements required by the cycle.
| Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution |
|---|---|---|---|---|---|---|---|---|---|
| AEP/OVEC |
06KYGER-05SPORN 345.0 kV Ckt 1 line
248005 to 242528 ckt 1 |
AEP_P1-2_#7441_100545_SRT-A
CONTINGENCY 'AEP_P1-2_#7441_100545_SRT-A' OPEN BRANCH FROM BUS 242928 TO BUS 246999 CKT 1 /*05MARYSV 765.0 - 05SORENS 765.0 END |
Single | DC | 105.64 % | 1204.0 | B | 1271.86 | 21.89 |
| AEP/DEI |
05EUGENE-08CAYSUB 345.0 kV Ckt 1 line
243221 to 249504 ckt 1 |
EXT_249521 08SUGCRK 345 347340 7KANSAS 345 1 _SRT-L
CONTINGENCY 'EXT_249521 08SUGCRK 345 347340 7KANSAS 345 1 _SRT-L' OPEN BRANCH FROM BUS 249521 TO BUS 347340 CKT 1 /*08SUGCRK 345.0 - 7KANSAS 345.0 END |
Single | AC | 103.06 % | 1374.0 | B | 1416.03 | 32.43 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
| Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution |
|---|---|---|---|---|---|---|---|---|---|
| AEP/DEI |
05EUGENE-08CAYSUB 345.0 kV Ckt 1 line
243221 to 249504 ckt 1 |
AEP_P1-2_#672_1713_SRT-A-1
CONTINGENCY 'AEP_P1-2_#672_1713_SRT-A-1' OPEN BRANCH FROM BUS 243217 TO BUS 963840 CKT 1 /*05DEQUIN 345.0 - AG1-237 TP 345.0 END |
Single | AC | 101.15 % | 1374.0 | B | 1389.74 | 22.03 |
Light Load Potential Congestion due to Local Energy Deliverability
The following flowgates remain after considering the topology reinforcements required by the cycle.
| Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution |
|---|---|---|---|---|---|---|---|---|---|
| AEP/DEI |
05EUGENE-08CAYSUB 345.0 kV Ckt 1 line
243221 to 249504 ckt 1 |
EXT_249521 08SUGCRK 345 347340 7KANSAS 345 1 _SRT-L
CONTINGENCY 'EXT_249521 08SUGCRK 345 347340 7KANSAS 345 1 _SRT-L' OPEN BRANCH FROM BUS 249521 TO BUS 347340 CKT 1 /*08SUGCRK 345.0 - 7KANSAS 345.0 END |
OP | AC | 100.89 % | 1374.0 | B | 1386.28 | 32.43 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
(No impacts were found for this analysis)
Short Circuit Analysis
The Phase III Short circuit analysis was conducted for the following two study scenarios
- Scenario 1 - TC1 Projects Impact;
- Scenario 2 - TC1 Topology-Changing Upgrade Impacts;
The starting TC1 Phase III short circuit case is an updated Phase II case that accounted for the DPII outcomes (project changes & withdrawals) and other pre-TC1 changes. The starting Phase III case was utilized for the Scenario 1 studies to determine the impact of TC1 projects without modeling any topology-changing upgrades required for TC1. To conduct the Scenario 2 studies, the required topology-changing upgrades from the latest Load Flow & Stability studies were incorporated into the Scenario 1 case and utilized for the Scenario 2 studies to determine the impact of the topology-changing upgrades on the short circuit results from Scenario 1
Based on PJM Short Circuit Analysis, this project did not contribute >1% fault duty to previously identified overduty breakers, nor did it cause any new overduty breakers.
Stability Analysis
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
Cluster | Project | Fuel Type | Transmission Owner | MFO | MWE | MWC | Point of Interconnection |
62 | AF2-173 | Solar | AEP | 140 | 140 | 84 | Desoto 345 kV Substation |
AF2-177 | Wind | AEP | 200 | 200 | 26 | Sorenson – Desoto #2 345 kV Line | |
AF2-407 | Battery Storage | AEP | 300 | 300 | 300 | Fall Creek 345 kV Substation | |
AG1-367 | Solar | AEP | 100 | 100 | 60 | DeSoto 345 kV Substation | |
AG1-375 | Solar | AEP | 100 | 100 | 100 | Sorenson – Desoto #2 345 kV Line |
Reactive Power Analysis
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
Steady State Voltage Analysis complete, no voltage issues found.
New Service Request Dependencies
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.
| New Service Requests Dependencies | ||
|---|---|---|
| Project ID | Project Name | Status |
| AA1-018 | Powerton-Goodings Grove | In Service |
| AB1-006 | Meadow Lake 345kV | In Service |
| AB2-047 | Brokaw-Pontiac Midpoint | In Service |
| AB2-070 | Mt. Pulaski-Brokaw | In Service |
| AC1-033 | Kewanee 138 kV | In Service |
| AC1-053 | Lanesville-Brokaw | Under Construction |
| AC1-168 | Kewanee-Streator | Suspended |
| AC1-174 | Losantville 345kV | In Service |
| AC1-175 | Losantville 345kV | In Service |
| AC1-214 | Crescent Ridge | In Service |
| AC2-090 | Losantville 345kV | In Service |
| AC2-111 | College Corner 138kV | Engineering & Procurement |
| AC2-176 | Jay 138 kV | In Service |
| AD1-043 | Makahoy 138 kV | Withdrawn |
| AD1-100 | Loretto-Wilton 345 kV & Braidwood-Davis Creek 345 kV | Under Construction |
| AD1-128 | Modoc-Delaware 138 kV | Under Construction |
| AD1-148 | Brokaw-Lanesville | In Service |
| AD2-047 | Davis Creek 138 kV | Suspended |
| AD2-071 | Strawton-Deer Creek 138 kV | Suspended |
| AE1-172 | Loretto-Wilton Center | Active |
| AE1-207 | Mississinewa-Gaston 138 kV | Suspended |
| AE1-208 | Delaware-Van Buren 138 kV | Suspended |
| AE1-209 | Desoto 345 kV | Suspended |
| AE1-210 | Desoto 345 kV | Suspended |
| AE2-089 | Pennville-Adams 138 kV | Engineering & Procurement |
| AE2-169 | Delaware-Van Buren 138 kV | Suspended |
| AE2-172 | Mississinewa-Gaston 138 kV | Suspended |
| AE2-173 | McLean 345 kV | Active |
| AE2-219 | Bluff Point-Randolph 138 kV | Suspended |
| AE2-220 | Losantville 345 kV | Engineering & Procurement |
| AE2-223 | McLean 345 kV | Active |
| AE2-234 | Liberty Center-Buckeye Tap 69 kV | Engineering & Procurement |
| AE2-276 | Sullivan 345kV | Engineering & Procurement |
| AE2-297 | Madison-Tanners Creek 138 kV | In Service |
| AF1-045 | Cedarville-Ford 138 kV | Suspended |
| AF1-071 | College Corner 138 kV | Engineering & Procurement |
| AF1-088 | Sullivan 345 kV | Active |
| AF1-090 | Kincaid-Pana | Engineering & Procurement |
| AF1-092 | Huntington Jct. 138 kV | Suspended |
| AF1-118 | Sorenson-Desoto 345 kV | Engineering & Procurement |
| AF1-119 | Keystone-Desoto 345 kV | Engineering & Procurement |
| AF1-202 | Keystone-Desoto 345 kV | Under Construction |
| AF1-204 | Eugene 345 kV | Active |
| AF1-223 | Keystone-Desoto 345 kV | Under Construction |
| AF1-268 | Desoto-Jay 138 kV | Engineering & Procurement |
| AF2-008 | Sullivan 345 kV | Active |
| AF2-032 | Kincaid 345 kV | Engineering & Procurement |
| AF2-068 | Jay 138 kV | Active |
| AF2-069 | Crescent Ridge 138 kV | Active |
| AF2-078 | Reynolds-Olive #1 345 kV | Engineering & Procurement |
| AF2-162 | Keystone-Desoto 345 kV | Engineering & Procurement |
| AF2-173 | Desoto 345 kV | Active |
| AF2-177 | Sorenson-DeSoto #2 345 kV | Active |
| AF2-226 | Katydid Road 345 kV | Active |
| AF2-252 | Blue Mound 345 kV | Engineering & Procurement |
| AF2-317 | Hill Topper 345 kV | In Service |
| AF2-319 | Katydid Road 345 kV | Active |
| AF2-335 | Delaware-Royerton 138 kV | Active |
| AF2-352 | Blue Mound 345 kV | Engineering & Procurement |
| AF2-370 | Delaware-Royerton 138 kV | Active |
| AF2-388 | Keystone-Desoto 345 kV | Active |
| AF2-408 | Fall Creek 138 kV | Engineering & Procurement |
| AF2-441 | Burnham 138kV | Active |
| AG1-017 | Jay 138 kV | Under Construction |
| AG1-047 | Jay 138 kV | Engineering & Procurement |
| AG1-207 | Vandalia 69 kV | Engineering & Procurement |
| AG1-236 | Lanesville-Brokaw 345 kV | Active |
| AG1-237 | Dequine-Eugene 345 kV | Engineering & Procurement |
| AG1-297 | Hanna-Tanners Creek 345 kV | Active |
| AG1-324 | Jay-Desoto 138 kV | Engineering & Procurement |
| AG1-367 | DeSoto 345 kV | Active |
| AG1-375 | Sorenson-Desoto 345 kV | Active |
| AG1-398 | Brokaw-Lanesville 345 kV | In Service |
| AG1-406 | Walnut Grove-Asahi 69 kV | Active |
| AG1-414 | Mississinewa 138 kV | Engineering & Procurement |
| AG1-433 | Keystone-DeSoto 345 kV | Active |
| AG1-460 | Kincaid-Pana 345 kV | Active |
| AG1-478 | Wilmington 34.5 kV | Engineering & Procurement |
| AG1-512 | University Park North 345 kV | Withdrawn |
| AG1-555 | Dequine 345 kV | Engineering & Procurement |
| V3-007 | Desoto-Tanners Creek #1 345kV | In Service |
| W2-048 | Brokaw-Lanesville | In Service |
| W4-005 | Blue Mound-Latham | In Service |
| X2-022 | Brokaw-Lanesville | In Service |
| Z2-087 | Pontiac MidPoint-Brokaw 345kV | In Service |
| Z2-115 | Deer Creek 12.47kV | In Service |
Affected System - PJM Identified Violations
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.
| AF2-407 System Reinforcements: | TO | Trans Owner ID | Title | Category | Allocated Cost ($USD) | |||||
|---|---|---|---|---|---|---|---|---|---|---|
| DEI | DEI_TC1_16079 | Reconductor Eugene to Cayuga 345kV #1 line with 4000A conductor. New rating 2430 MVA. | Cost Allocated | $498,894 | ||||||
| Grand Total: | $498,894 | |||||||||
System Reinforcement
- Type
- Load Flow
- TO
- DEI
- RTEP ID / TO ID
- (Pending) / DEI_TC1_16079
- Title
- Reconductor Eugene to Cayuga 345kV #1 line with 4000A conductor. New rating 2430 MVA.
- Description
- Reconductor Eugene to Cayuga 345kV #1 line with 4000A conductor. New rating 2430 MVA.
- Total Cost ($USD)
- $12,000,000
- Allocated Cost ($USD)
- $498,894
- Time Estimate
- 8 Months
Contributor
| Facility | Contingency | |
|---|---|---|
| 05EUGENE-08CAYSUB 345.0 kV Ckt 1 line | (Any) |
| Project | MW Impact | Percent Allocation | Allocated Cost ($USD) |
|---|---|---|---|
|
AE2-223
⧉
McLean 345kV (ComEd): This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AE2-223, AF2-225 |
11.3 MW | 1.4% | $173,898 |
|
AE2-261
⧉
Kincaid Pana Tap - ComEd: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AE2-261, AG1-460 |
26.2 MW | 3.4% | $403,577 |
|
AF1-088
⧉
Sullivan 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AF1-088, AF2-008, AH1-084 |
125.2 MW | 16.0% | $1,925,781 |
| AF1-204 | 135.4 MW | 17.4% | $2,083,172 |
|
AF2-008
⧉
Sullivan 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AF1-088, AF2-008, AH1-084 |
125.2 MW | 16.0% | $1,925,781 |
|
AF2-225
⧉
McLean 345kV (ComEd): This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AE2-223, AF2-225 |
11.3 MW | 1.4% | $173,898 |
| AF2-407 | 32.4 MW | 4.2% | $498,894 |
| AG1-226 | 238.9 MW | 30.6% | $3,675,742 |
| AG1-236 | 17.0 MW | 2.2% | $261,016 |
| AG1-297 | 31.1 MW | 4.0% | $478,742 |
| AG1-374 | 23.3 MW | 3.0% | $359,010 |
|
AG1-460
⧉
Kincaid Pana Tap - ComEd: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AE2-261, AG1-460 |
2.6 MW | 0.3% | $40,490 |
Affected System - Non-PJM Identified Violations
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.
Affected System network upgrade costs are included in the Adverse Study Impact calculation for DP3. See the Adverse Test Eligibility section of this Phase III SIS report.
| Impacted Facility | Transmission Owner | Reinforcement | Cost | Cost Allocated to AF2-407 | Scenarios |
|---|---|---|---|---|---|
|
LGEE |
Hardin to Central Hardin 138kV line Reconductor
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. |
$6,654,599 | $1,656 | |
|
LGEE |
Bardstown Ind Tap-E Bardstown 69 kV MOT
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. |
$343,630 | $5,140 | |
|
LGEE |
Bardstown Ind Tap-Bardstown 69 kV Reconductor
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. |
$3,761,697 | $48,641 | |
|
LGEE |
Hodgenville-Hodgenville EKPC 69 kV MOT
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. |
$443,658 | $10,489 | |
|
LGEE |
Millersburg-Paris 69 kV MOT
Increase the maximum operating temperature to 145F of the 8.1 miles of 3/0 6x1 ACSR in the Millersburg-Paris 12 69kV line. |
$6,375,732 | $170,018 |
System Reinforcements
Based on the Phase III analysis results, this project is contingent on and may have cost responsibility for the following System Reinforcements:
PJM evaluated the impact of topology changing reinforcements to mitigate the impacts driven by New Service Requests. PJM determined which reinforcements were eliminated as a result of modeling the topology changing reinforcements. PJM then grouped the topology changing and eliminated reinforcements by region and computed a discount factor to apply to reinforcements to reduce the cost of all these reinforcements down to the cost of contstructing only the topology changing reinforcements. For additional details, please click the icon below
Shown below are the details of the cost allocated, contingent, eliminated, topology and potential aggregate contributor reinforcements for this project. Please refer to the System Reinforcement table above and the information below for more detail.
System Reinforcement: n7881
- Type
- Load Flow
- TO
- OVEC
- RTEP ID / TO ID
- n7881 / OVEC0001a
- Title
- Sag mitigations to bring the Dearborn – Pierce 345 kV line up to a maximum operating temperature of 311° F
- Description
- •Remove and replace sixteen (16) existing double circuit towers with taller double circuit custom steel poles. (Towers 11, 14, 45, 47, 52, 57, 59, 61, 63, 66, 67, 71, 77, 84, 91, and 96) •Remove and replace two (2) existing river crossing lattice towers with taller lattice structures. (Towers 2 and 140)
- Total Cost ($USD)
- $24,006,000
- Discounted Total Cost ($USD)
- $24,006,000
- Allocated Cost ($USD)
- $4,519,578
- Time Estimate
- 38 Months
Contributor
| Facility | Contingency | |
|---|---|---|
| 06DEARB1-06PIERCE 345.0 kV Ckt 1 line | (Any) |
| Project | MW Impact | Percent Allocation | Allocated Cost ($USD) |
|---|---|---|---|
|
AF2-173
⧉
Desoto 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AE1-209, AE1-210, AF2-173, AG1-367 |
12.9 MW | 10.1% | $2,426,183 |
|
AF2-177
⧉
Sorenson - Desoto 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AF2-177, AG1-375 |
15.0 MW | 11.7% | $2,812,841 |
|
AF2-388
⧉
Keystone - Desoto 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AF2-388, AG1-433 |
14.5 MW | 11.4% | $2,730,442 |
| AF2-407 | 24.1 MW | 18.8% | $4,519,578 |
| AG1-297 | 37.4 MW | 29.2% | $7,012,206 |
|
AG1-367
⧉
Desoto 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AE1-209, AE1-210, AF2-173, AG1-367 |
9.2 MW | 7.2% | $1,733,015 |
|
AG1-375
⧉
Sorenson - Desoto 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AF2-177, AG1-375 |
7.5 MW | 5.9% | $1,406,420 |
|
AG1-433
⧉
Keystone - Desoto 345kV - AEP: This project's cost allocation eligibility was based on the grouped impact of all New Service Requests which shared this POI within this cycle. The following project shared this POI:
AF2-388, AG1-433 |
7.3 MW | 5.7% | $1,365,315 |
System Reinforcement
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- (Pending) / AEP_TC1_13727
- Title
- AEP SE rating is 1868 MVA
- Description
- AEP SE rating is 1868 MVA
- Total Cost ($USD)
- $0
- Discounted Total Cost ($USD)
- $0
- Allocated Cost ($USD)
- $0
- Time Estimate
- 0 to 1 Months
Note: This reinforcement is fictitious and will not be cost allocated to projects. It is listed for information purposes only.
| Facility | Contingency | |
|---|---|---|
| 05EUGENE-08CAYSUB 345.0 kV Ckt 1 line | (Any) |
System Reinforcement: b3788.1
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3788.1 / B3788.1
- Title
- Replace limiting station elements at Kyger Creek
- Description
- Upgrade existing 345 kV terminal equipment at Kyger Creek on the Kyger Creek-Sporn 345 kV line. Projected in-service date 6/1/2028 Replace AEP-owned station takeoff riser and breaker BB risers at OVEC-owned Kyger Creek station.
- Cost Information
- Time Estimate
- Nov 18 2027
Contingent Note: Although AF2-407 may not presently have cost responsibility for this upgrade, AF2-407 may need this upgrade in-service to be deliverable to the PJM system. If AF2-407 desires to come into service prior to completion of the upgrade, the Project Developer will need to request PJM to perform an interim study to determine if they would be deliverable for all or a portion of their output for each delivery year until the upgrade is complete.
| Facility | Contingency | |
|---|---|---|
| 05SPORN-06KYGER 345.0 kV Ckt 1 line | (Any) |
System Reinforcement: b3788.2
- Type
- Load Flow
- TO
- OVEC
- RTEP ID / TO ID
- b3788.2 / B3788.2
- Title
- Replace limiting station elements at Kyger Creek
- Description
- Upgrade existing 345 kV terminal equipment at Kyger Creek on the Kyger Creek-Sporn 345 kV line. Projected in-service date 6/1/2028 Replace OVEC-owned breaker AA risers, bus work, and breaker AA disconnect switches at OVEC-owned Kyger Creek station.
- Cost Information
- Time Estimate
- Jun 01 2028
Contingent Note: Although AF2-407 may not presently have cost responsibility for this upgrade, AF2-407 may need this upgrade in-service to be deliverable to the PJM system. If AF2-407 desires to come into service prior to completion of the upgrade, the Project Developer will need to request PJM to perform an interim study to determine if they would be deliverable for all or a portion of their output for each delivery year until the upgrade is complete.
| Facility | Contingency | |
|---|---|---|
| 05SPORN-06KYGER 345.0 kV Ckt 1 line | (Any) |
Attachments
AF2-407 One Line Diagram
[1]Winter load flow analysis will be performed starting in Transition Cycle 2.