AF1-296 Final System Impact Study (Retool 1) Report
v1.00 released 2025-12-08 18:17
Garden Plain 138 kV
33.6 MW Capacity / 190.89 MW Energy
Introduction
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 Gipper Wind Farm, LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Commonwealth Edison Company.
Preface
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:
- Negotiate, execute and enter into the applicable final interconnection related service agreement found in Tariff, Part IX;
- Conduct any remaining analyses or updated analyses based on New Service Requests withdrawn during Decision Point III (DP3); and
- Adjust the security obligation based on New Service Requests withdrawn during Decision Point III and/or during the Final Agreement Negotiation Phase.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.
General
The Project Developer has proposed a Wind generating facility located in the Commonwealth Edison Company zone — Whiteside County, Illinois. The installed facilities will have a total capability of 190.89 MW with 33.6 MW of this output being recognized by PJM as Capacity.Project Information
Physical Interconnection Facility Study
The transmission owner has completed the Physical Interconnection Facilities Study. This report is available for download.
Point of Interconnection
AF1-296 will interconnect on the ComEd transmission system by a direct connection into the TSS 132 Garden Plain 138 kV substation.
Cost Summary
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 AF1-296 project has the following allocation of costs for interconnection. The Security amount required after the Final SIS and revised agreements is also shown below.
| Cost Summary | |||
|---|---|---|---|
| Description | Cost Allocated to AF1-296 | Cost Subject to Security* | |
| Transmission Owner Interconnection Facilities (TOIF) | $717,375 | $717,375 | |
| Other Scope | $0 | $0 | |
| Option To Build Oversight | $0 | $0 | |
| Physical Interconnection Network Upgrades | |||
| Stand Alone Network Upgrades | $0 | $0 | |
| Network Upgrades | $11,672,026 | $11,672,026 | |
| System Reliability Network Upgrades | |||
| Steady State Thermal & Voltage (SP & LL) | $9,366,298 | $9,366,298 | |
| Transient Stability | $0 | $0 | |
| Short Circuit | $0 | $0 | |
| Transmission Owner Analysis | |||
| SubRegional | $0 | $0 | |
| Distribution | $0 | $0 | |
| Affected System Reinforcements | |||
| AFS - PJM Violatons | $0 | $0 | |
| AFS - Non-PJM Violations | $95,169 | $0 | |
| Total | $21,850,868 | $21,755,699 | |
* 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.
Security Requirement
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 AF1-296
Security has been calculated for the AF1-296 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.
Security Due for AF1-296
In accordance with Tariff, Part VII, Subpart D, section 314(B)(4)(a) (Final Agreement Negotiation Phase) failure to provide any required adjustments to Security within the 15 Business Day period will result in the New Service Request project being terminated and withdrawn.
Please see the cover letter for more details on Letter of Credit/Wire details to satisfy the additional Security requirement.
If no additional Security is required, please coordinate with your assigned Project Manager to initiate any refunds of Security reductions.
Transmission Owner Scope of Work
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
| Network Upgrades | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| n9629.0 | Expand the TSS 132 Garden Plain substation to accommodate the AF1-296 project. | $6,837,831 | $2,846,065 | $1,819,139 | $168,991 | $11,672,026 | $11,672,026 |
| Transmission Owner Interconnection Facilities | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) | Construct Transmission Owner Interconnection Facilities from the Point of Change in Ownership to the TSS 132 substation. | $185,242 | $455,788 | $49,282 | $27,063 | $717,375 | $717,375 |
Based on the scope of work for the Interconnection Facilities, it is expected to take 36 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.
Notes on Cost Estimate:
- These estimates are Order-of-Magnitude estimates of the costs that ComEd would bill to the Project Developer for this interconnection. These estimates are based on a one-line electrical diagram of the project and the information provided by the Project Developer.
- There were no site visits performed for these estimates. There may be costs related to specific site related issues that are not identified in these estimates. The site reviews will be performed during the Facilities Study or during detailed engineering.
- These estimates are not a guarantee of the maximum amount payable by the Project Developer and the actual costs of ComEd's work may differ significantly from these estimates. The Project Developer will be responsible for paying actual costs of ComEd's work in accordance with the PJM Open Access Transmission Tariff.
- The Project Developer is responsible for all engineering, procurement, testing and construction of all equipment on the Project Developer’s side of the Point of Change in Ownership.
These cost estimates do not include cost of acquiring right-of-way for the transmission line and purchasing any additional land, if needed, for the line terminations.
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. ComEd 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.
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.Meteorological Data Reporting Requirement
The wind generation facility shall provide the Transmission Provider with site-specific meteorological data including:Transmission Owner Requirements
- Wind speed (meters/second) - (Required)
- Wind direction (decimal degrees from true north) - (Required)
- Ambient air temperature (Fahrenheit) - (Required)
- Air Pressure (Hectopascals) - (Required)
- Humidity (Percent) - (Accepted, not required)
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.
Summer Peak Analysis
The New Service Request AF1-296 was evaluated as a 190.9 MW (33.6 MW Capacity) injection in the ComEd area.
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.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD1 | CE | AF2-041 TP-ELECT JCT; B 345.0 kV Ckt 1 line | COMED_P4_006-45-BT3-8___SRT-A | Breaker | AC | 115.39 % | 1837.0 | STE | 2119.77 | 44.03 | |
| GD1 | CE | AF2-041 TP-ELECT JCT; B 345.0 kV Ckt 1 line | COMED_P4_006-45-BT3-4___SRT-A | Breaker | AC | 114.8 % | 1837.0 | STE | 2108.84 | 43.85 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD1 | AEP/NIPS | 17STILLWELL-05DUMONT 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 144.48 % | 1075.0 | B | 1553.15 | 4.03 | |
| GD1 | AEP/NIPS | 17STILLWELL-05DUMONT 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 144.47 % | 1075.0 | B | 1553.1 | 4.03 | |
| GD1 | AEP/NIPS | 17STILLWELL-05DUMONT 345.0 kV Ckt 1 line | Base Case | Single | AC | 109.11 % | 1075.0 | A | 1172.98 | 2.34 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 100.85 % | 1399.0 | B | 1410.83 | 3.62 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 100.84 % | 1399.0 | B | 1410.81 | 3.62 | |
| GD1 | CE | GOODINGS ;4B-GOODINGS ;3B 345.0 kV Ckt 1 line | COMED_P4-6_116-345-R______SRT-A | Breaker | AC | 107.57 % | 2297.0 | STE | 2470.99 | 17.2 | |
| GD1 | CE | GOODINGS ;4B-GOODINGS ;3B 345.0 kV Ckt 1 line | COMED_P4_116-45-L11614__SRT-A | Breaker | AC | 103.27 % | 2297.0 | STE | 2372.1 | 15.17 | |
| GD1 | CE | GOODINGS ;4B-GOODINGS ;3B 345.0 kV Ckt 1 line | COMED_P4_112-45-BT4-5___SRT-A | Breaker | AC | 100.41 % | 2297.0 | STE | 2306.46 | 18.87 |
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.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD1 | CE | AF2-041 TP-ELECT JCT; B 345.0 kV Ckt 1 line | Base Case | OP | AC | 126.28 % | 1334.0 | A | 1684.59 | 32.67 | |
| GD1 | CE | CHERRY VA; B-GARDEN PR; R 345.0 kV Ckt 1 line | COMED_P1-2_345-L0626__B-R_SRT-A | OP | AC | 116.23 % | 1479.0 | B | 1719.04 | 19.84 | |
| GD1 | CE | CHERRY VA; B-GARDEN PR; R 345.0 kV Ckt 1 line | Base Case | OP | AC | 103.49 % | 1201.0 | A | 1242.87 | 14.29 | |
| GD1 | CE | ELECT JCT; B-LOMBARD ; B 345.0 kV Ckt 1 line | Base Case | OP | AC | 106.45 % | 1201.0 | A | 1278.42 | 10.95 | |
| GD1 | CE | ELECT JCT; B-LOMBARD ; B 345.0 kV Ckt 1 line | COMED_P1-2_345-L11120_R-N_SRT-A | OP | AC | 100.63 % | 1479.0 | B | 1488.3 | 11.47 | |
| GD1 | CE | GARDEN PR; R-SILVER LK; R 345.0 kV Ckt 1 line | COMED_P1-2_345-L0626__B-R_SRT-A | OP | AC | 126.4 % | 1479.0 | B | 1869.42 | 19.84 | |
| GD1 | CE | GARDEN PR; R-SILVER LK; R 345.0 kV Ckt 1 line | Base Case | OP | AC | 115.04 % | 1201.0 | A | 1381.59 | 14.29 | |
| GD1 | CE | LEE CO EC;BP-BYRON ; B 345.0 kV Ckt 1 line | COMED_P1-2_345-L15502_B-R_SRT-A-2 | OP | AC | 115.83 % | 1726.0 | B | 1999.26 | 47.28 | |
| GD1 | CE | NELSON ; B-AF2-041 TP 345.0 kV Ckt 1 line | COMED_P1-2_345-L0627__B-R_SRT-A | OP | AC | 108.05 % | 1656.0 | B | 1789.35 | 43.85 | |
| GD1 | CE | NELSON ; B-AF2-041 TP 345.0 kV Ckt 1 line | Base Case | OP | AC | 103.46 % | 1334.0 | A | 1380.1 | 32.67 | |
| GD1 | CE/MEC | QUAD 6-7-SUB 91 3 345.0 kV Ckt 1 line | EXT_636600 SUB 39 3 345 636605 MEC CORDOVA3 345 1 _SRT-S | OP | AC | 103.43 % | 1471.0 | B | 1521.53 | 12.35 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
(No flowgates were eliminated after considering the topology reinforcements required by the cycle.)
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 AF1-296 was evaluated as a 190.9 MW injection in the ComEd area.
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.
(No impacts were found for this analysis)
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD1 | AEP/NIPS | 17STILLWELL-05DUMONT 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 126.34 % | 1075.0 | B | 1358.12 | 17.62 | |
| GD1 | AEP/NIPS | 17STILLWELL-05DUMONT 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | DC | 121.52 % | 1075.0 | B | 1306.39 | 17.62 | |
| GD1 | AEP/NIPS | 17STILLWELL-05DUMONT 345.0 kV Ckt 1 line | AEP_P4_#2978_05DUMONT 765_B_SRT-A | Breaker | AC | 119.42 % | 1075.0 | B | 1283.78 | 17.33 | |
| GD1 | AEP/CE | AF2-359 TP-05OLIVE 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 124.77 % | 971.0 | B | 1211.56 | 13.03 | |
| GD1 | AEP/CE | AF2-359 TP-05OLIVE 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 124.6 % | 971.0 | B | 1209.9 | 13.03 | |
| GD1 | AEP/CE | AF2-359 TP-05OLIVE 345.0 kV Ckt 1 line | COMED_P4_112-65-BT4-5___SRT-A | Breaker | AC | 110.59 % | 971.0 | B | 1073.81 | 13.03 | |
| GD1 | AEP/CE | AF2-359 TP-05OLIVE 345.0 kV Ckt 1 line | COMED_P4_112-65-BT3-4___SRT-A | Breaker | AC | 110.59 % | 971.0 | B | 1073.8 | 13.03 | |
| GD1 | CE/NIPS | BURNHAM ;0R-17MUNSTER 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 100.96 % | 1441.0 | B | 1454.81 | 14.8 | |
| GD1 | CE/NIPS | BURNHAM ;0R-17MUNSTER 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 100.81 % | 1441.0 | B | 1452.61 | 14.8 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 116.58 % | 1399.0 | B | 1630.9 | 15.69 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 116.39 % | 1399.0 | B | 1628.28 | 15.69 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | AEP_P4_#2978_05DUMONT 765_B_SRT-A | Breaker | AC | 105.23 % | 1399.0 | B | 1472.14 | 15.64 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | COMED_P4_112-65-BT4-5___SRT-A | Breaker | AC | 104.33 % | 1399.0 | B | 1459.57 | 15.7 | |
| GD1 | CE/NIPS | CRETE EC ;BP-17STJOHN 345.0 kV Ckt 1 line | Base Case | Single | AC | 102.15 % | 1091.0 | A | 1114.47 | 10.42 | |
| GD1 | CE | E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 116.61 % | 1399.0 | B | 1631.33 | 15.69 | |
| GD1 | CE | E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 116.42 % | 1399.0 | B | 1628.71 | 15.69 | |
| GD1 | CE | E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | AEP_P4_#2978_05DUMONT 765_B_SRT-A | Breaker | AC | 105.23 % | 1399.0 | B | 1472.21 | 15.64 | |
| GD1 | CE | E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | COMED_P4_112-65-BT4-5___SRT-A | Breaker | AC | 104.33 % | 1399.0 | B | 1459.63 | 15.7 | |
| GD1 | CE | E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | Base Case | Single | AC | 102.15 % | 1091.0 | A | 1114.43 | 10.42 | |
| GD1 | CE | UNIV PK N;RP-AF2-359 TP 345.0 kV Ckt 1 line | 765-L11215__-S_SRT-A | Single | AC | 121.46 % | 970.0 | STE | 1178.14 | 13.03 | |
| GD1 | CE | UNIV PK N;RP-AF2-359 TP 345.0 kV Ckt 1 line | AEP_P1-2_#695_1681_SRT-A | Single | AC | 121.2 % | 970.0 | STE | 1175.66 | 13.03 | |
| GD1 | CE | UNIV PK N;RP-AF2-359 TP 345.0 kV Ckt 1 line | COMED_P4_112-65-BT4-5___SRT-A | Breaker | AC | 107.66 % | 970.0 | STE | 1044.28 | 13.03 | |
| GD1 | CE | UNIV PK N;RP-AF2-359 TP 345.0 kV Ckt 1 line | COMED_P4_112-65-BT3-4___SRT-A | Breaker | AC | 107.66 % | 970.0 | STE | 1044.26 | 13.03 |
Light Load 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.
The following flowgates remain after considering the topology reinforcements required by the cycle.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD1 | CE | AD1-100 TAP-WILTON ; B 345.0 kV Ckt 1 line | 765-L11216__-S_SRT-A | OP | AC | 116.87 % | 1528.0 | B | 1785.74 | 8.11 |
The following flowgates were eliminated after considering the topology reinforcements required by the cycle.
(No flowgates were eliminated after considering the topology reinforcements required by the cycle.)
Short Circuit Analysis
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.
Stability Analysis
Analysis Complete - No Issues
Executive Summary
New Service Requests AF1-296, AG1-462 and AG1-553 in PJM Transition Cycle 1, Cluster 17 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 17 projects.
This analysis is effectively a screening study to determine whether the addition of the Cluster 17 projects will meet the dynamics requirements of the NERC, ComEd 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 17 projects have been dispatched online at maximum power output, with 1.0 pu voltage at the terminal bus, except AF1-296, which was allowed to have a terminal voltage of 1.027 pu.
Cluster 17 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 197 contingencies were studied, each with a 20 second simulation time period. Studied faults included:
- Steady-state operation (20 second run);
- Three-phase faults with normal clearing time;
- Three-phase bus faults with normal clearing time;
- Three-phase faults with single-phase delayed clearing due to a stuck breaker (IPO breaker with FD Logic).
- Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO Breakers with A-contact Logic);
- Three-phase faults with single-phase delayed clearing due to a stuck breaker (GO Breakers with FD Logic);
- Three-phase faults with three-phase delayed clearing due to a stuck breaker (GO breakers with FD Logic);
- Single-phase faults with stuck breaker (for MISO substations);
- Three-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;
- 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 (for MISO substations);
- Three-phase faults with loss of multiple-circuit tower line.
No relevant high-speed reclosing (HSR) contingencies were identified for this study.
Buses at which the faults listed above were applied are:
- Cordova E.C. TSS 940 (AG1-553/AG1-462 POI) 345 kV
- Cordova M.E.C. 345 kV
- Nelson TSS 155 (AE1-134/AA2-030/AA1-146 POI) 345 kV
- E. Molin (Barstow SUB. 39 M.E.C.) 345 kV
- Quad Cities STA. 4 345 kV
- Garden Plain TSS 132 (AF1-296 POI) 138 kV
- Nelson TSS 155 138 kV
- AF2-392 TAP 138 kV
- Sterling Steel (ESS H71) 138 kV
- Rock Falls TSS 133 138 kV
- Albany S.S. 138 kV & 161 kV
- Beaver Channel 161 kV
- York 161 kV
- Savanna 161 kV
- Rock Creek 161 kV
- SUB 49 161 kV
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:
- Cluster 17 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
- The system with Cluster 17 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.
- 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).
- No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.
AG1-553, AG1-462 and AF1-296 meet the 0.95 leading and lagging PF requirement.
The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away of Cluster 17. The CSCR results for AF1-296 are summarized in Table 7 through Table 17 and revealed a minimum and maximum CSCR values of 2.64 for P4.84 & P4.86 and 4.45 for P1.64, respectively. The CSCR results for AG1-553 and AG1-462 revealed a minimum and maximum CSCR values of 3.81 for P4.08 & P4.10 and 7.24 for P1.02 & P4.03, respectively.
Specific findings from the simulations for each of the queue projects of Cluster 17 are indicated below.
AG1-553 and AG1-462
The IPCMD and IQCMD states in the REGCA1 models of AG1-553 GEN 1&2 and AG1-462 GEN 1 showed erratic behavior for some contingencies in which AG1-553 or AG1-462 generators have been disconnected as part of the contingency event. Since the machines are 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.
High voltage spikes on the terminal voltages of AG1-462 and AG1-553, occurred in the simulations immediately after fault clearing for a few 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.”
AF1-296
For 24 contingencies out of 197, the steady state post-contingency terminal voltage of AF1-296 went slightly above 1.05 pu (Et ≈ 1.056 pu – 14 contingencies, Et ≈ 1.051 pu – 10 contingencies). This is due to the fact that the terminal voltage of AF1-296 pre-contingency is 1.027 pu.
High voltage spikes at the terminals of AF1-296 and its POI, Garden Plain 138 kV, occurred in the simulations immediately after fault clearing for some of the contingencies studied (i.e. fault where spike is observed]). As, with the WECC models, these voltage spikes are considered a consequence of the model’s limited bandwidth, integration time step and the way it interfaces with the network solution. Therefore, it is estimated that they do not represent the performance of actual equipment and can be ignored in most cases. The spike at Garden Plain is a consequence of the spike at the terminals of AF1-296.
No mitigations were found to be required. However, it is recommended that the developer of AF1-296 provides an adjusted model that allows specifying the generator’s reactive power output at levels that support initial conditions with a terminal voltage close to 1.0 pu.
Table 1: Cluster 17 Projects
Cluster | Project | Fuel Type | Transmission Owner | MFO | MWE | MWC | Point of Interconnection |
17 | AF1-296 | Wind | ComEd | 190.89 | 190.89 | 33.6 | Garden Plain 138 kV |
AG1-462 | Solar | ComEd | 255 | 255 | 153 | Cordova 345 kV | |
AG1-553 | Solar | ComEd | 260 | 260 | 0 | Cordova 345 kV |
Reactive Power Analysis
The reactive power capability of AF1-296 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 is Not Required.
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 |
| AA1-146 | Nelson | In Service |
| AA2-030 | Nelson | In Service |
| AC1-033 | Kewanee 138 kV | In Service |
| AC1-214 | Crescent Ridge | In Service |
| AD1-013 | Twombly Road 138kV | Engineering & Procurement |
| AD2-134 | Shady Oaks | Partially in Service - Under Construction |
| AE1-114 | Maryland-Lancaster 138 kV | Active |
| AE1-134 | Nelson 345 kV | In Service |
| AF1-280 | Nelson-Lee County | Active |
| AF1-331 | Twombley Road | Engineering & Procurement |
| AF2-041 | Nelson-Electric Junction 345 kV | Active |
| AF2-182 | Nelson-Lee County 345 kV II | Active |
| AF2-199 | Nelson-Electric Junction 345 kV | Active |
| AF2-200 | Nelson-Electric Junction 345 kV | Active |
| AG1-044 | Whiteside County | In Service |
| AG1-462 | Cordova 345 kV | Active |
| AG1-553 | Cordova 345 kV | Active |
| Z1-073 | Mendota Hills | 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.
| AF1-296 System Reinforcements: | TO | Trans Owner ID | Title | Category | Allocated Cost ($USD) | |||||
|---|---|---|---|---|---|---|---|---|---|---|
| NIPS | b3775.8 | Upgrade existing terminal equipment at St. John on the existing Crete to St. John 345 kV line | Contingent | $0 | ||||||
| Grand Total: | $0 | |||||||||
System Reinforcement: b3775.8
- Type
- Load Flow
- TO
- NIPS
- RTEP ID / TO ID
- b3775.8
- Title
- Upgrade existing terminal equipment at St. John on the existing Crete to St. John 345 kV line
- Description
- Part of b3375 Baseline project. Upgrade the existing terminal equipment (substation conductor) at St. John on the existing Crete to St. John 345 kV line with bundled 2x1590 ACSR Lapwing
- Total Cost ($USD)
- $0
- Allocated Cost ($USD)
- $0
- Time Estimate
- Mar 30 2027
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 17STJOHN-CRETE EC ;BP 345.0 kV Ckt 1 line | (Any) |
|
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.
| Impacted Facility | Transmission Owner | Reinforcement | Cost | Cost Allocated to AF1-296 | Scenarios |
|---|---|---|---|---|---|
| DEI | DEI: Rebuild 1 mile of Wvrich - Rochester TP 69 kV DEI: Rebuild 1 mile of 69kV with 477ACSR/VR2 @ 100/120C the ratings assume that NIPSCO terminal upgrades would not limit our T-Line rating. $1.5M NIPSCO: Rebuild line, NIPSCO owns 0.037 miles of 0.9 mile line. NIPSCO portion included in Argos to Rochester tap mitigation/cost. | $1,500,000 | $5,847 |
|
| NIPS | NIPSCO: Rebuild line (.3miles)Wvrich - Rochester TP 69 kV DEI: Rebuild 1 mile of 69kV with 477ACSR/VR2 @ 100/120C the ratings assume that NIPSCO terminal upgrades would not limit our T-Line rating. $1.5M NIPSCO: Rebuild line, NIPSCO owns 0.037 miles of 0.9 mile line. NIPSCO portion included in Argos to Rochester tap mitigation/cost. | $0 | $0 |
|
| NIPS | Rebuild Argos - Plymouth 69 kV line Rebuild line, approx 10 miles | $12,654,948 | $47,531 |
|
| NIPS | Rebuild Argos - Rochester TP 69 kV Rebuild line, approx 3.2 miles | $4,049,583 | $15,784 |
|
| DEI | Install 144 MVAR cap bank at Gallagher sub. Install 144 MVAR cap bank at Gallagher sub. | $3,000,000 | $8,357 |
|
| DEI | Install 28.8 MVAR cap bank at Shoals sub Install 28.8 MVAR cap bank at Shoals sub | $3,000,000 | $6,329 |
|
| DEI | Install 28.8 MVAR cap bank at Avon East sub Install 28.8 MVAR cap bank at Avon East sub | $3,000,000 | $11,321 |
|
| ITCT | LRTP-33: Greentown - Sorenson - Lulu Install single circuit 765kV transmission line from the existing Greentown Substation to the existing Sorenson Substation, to the existing Lulu Substation. | $0 | $0 |
|
| DEI | LRTP-35: Southwest Indiana-Kentucky Install double circuit 345kV transmission line from the existing Petersburg Substation to the new Pike County Substation. Install single circuit 345kV transmission line from the new Pike County Substation to the existing Duff Substation, to the existing Culley Substation, to the existing Reid EHV Substation. | $0 | $0 |
|
| DEI | LRTP-36: Southeast Indiana Install single circuit 345kV transmission line from the new Madison County Substation to the existing Greensboro Substation. Install single circuit 138kV transmission line from the existing Decatur County Substation to the existing Greensburg Substation. Install double circuit 138kV transmission line from the existing Batesville Substation to the existing Hubbell Substation, to the existing Greendale Substation, to the existing Miami Fort Substation. | $0 | $0 |
|
| AMIL | LRTP-37: Maywood - Belleau - MRPD - Sioux - Bugle Install single circuit 345kV transmission line from the existing Maywood Substation to the existing Belleau Substation, to the new MRPD Substation, to the existing Sioux Substation, from the new MRPD Substation to the existing Bugle Substation. | $0 | $0 |
|
| NIPS | LRTP-42: Burr Oak - Schahfer Install single circuit 345kV transmission line from the existing Burr Oak Substation to the existing Schahfer Substation. | $0 | $0 |
|
| NIPS | LRTP-16: Morrison Ditch – Reynolds – Burr Oak Install single circuit 345kV transmission line from the existing Morrison Ditch Substation, to the existing Reynolds Substation, to the existing Burr Oak Substation, to the existing Leesburg Substation, to the existing Hiple Substation. | $0 | $0 |
|
System Reinforcements
Based on the Final System Impact Study analysis results, this project is contingent on and may have cost responsibility for the following System Reinforcements:
PJM evaluated the impact of topology changing reinforcements to mitigate the impacts driven by New Service Requests. PJM determined which reinforcements were eliminated as a result of modeling the topology changing reinforcements. PJM then grouped the topology changing and eliminated reinforcements by region and computed a discount factor to apply to reinforcements to reduce the cost of all these reinforcements down to the cost of contstructing only the topology changing reinforcements. For additional details, please click the icon below
Shown below are the details of the cost allocated, contingent, eliminated, topology and potential aggregate contributor reinforcements for this project. Please refer to the System Reinforcement table above and the information below for more detail.
System Reinforcement: n6639.2
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- n6639.2 / CE_NUN_L15502_4
- Title
- Reconductor the Electric Junction 345 kV line 93407, perform sag mitigation on 345 kV line 93407, upgrade one 345 kV circuit breaker and associated motor operated disconnect switches.
- Description
- • Reconductor 27.2 Miles of 345kV transmission line 93407 from structure 339 to structure 454 • Perform sag mitigation on 13.5 miles of 345kV transmission line 93407 from structure 454 to TSS 111 Electric Junction • Upgrade the existing substation TSS 111 Electric Junction by replacing L.93407 CB motor-operated disconnect switches on both sides of the breaker.
- Total Cost ($USD)
- $146,197,759
- Discounted Total Cost ($USD)
- $146,197,759
- Allocated Cost ($USD)
- $9,366,298
- Time Estimate
- 42 Months
Contributor
| Facility | Contingency | ||
|---|---|---|---|
| ELECT JCT; B-AF2-041 TP 345.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
| Project | MW Impact | Percent Allocation | Allocated Cost ($USD) |
|---|---|---|---|
| AE1-114 | 22.0 MW | 3.2% | $4,677,511 |
| AF1-280 ⧉ Nelson - Lee County 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: AF1-280, AF2-182 | 67.2 MW | 9.8% | $14,292,703 |
| AF1-296 | 44.0 MW | 6.4% | $9,366,298 |
| AF2-041 ⧉ Nelson-Electric Junction 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: AF2-041, AF2-199, AF2-200 | 159.4 MW | 23.2% | $33,916,212 |
| AF2-182 ⧉ Nelson - Lee County 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: AF1-280, AF2-182 | 100.8 MW | 14.7% | $21,438,948 |
| AF2-199 ⧉ Nelson-Electric Junction 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: AF2-041, AF2-199, AF2-200 | 53.1 MW | 7.7% | $11,305,333 |
| AF2-200 ⧉ Nelson-Electric Junction 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: AF2-041, AF2-199, AF2-200 | 118.1 MW | 17.2% | $25,123,010 |
| AG1-462 ⧉ Cordova 345 kV (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: AG1-462, AG1-553 | 60.7 MW | 8.8% | $12,912,297 |
| AG1-553 ⧉ Cordova 345 kV (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: AG1-462, AG1-553 | 61.9 MW | 9.0% | $13,165,446 |
System Reinforcement: b3775.6
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3775.6
- Title
- Perform sag study mitigation work on the Dumont-Stillwell 345 kV line
- Description
- Perform sag study mitigation work on the Dumont-Stillwell 345 kV line (remove a center-pivot irrigation system from under the line, allowing for the normal and emergency ratings of the line to increase, replace two structures and modify a third structure).
- Cost Information
- Time Estimate
- Nov 20 2026
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 05DUMONT-17STILLWELL 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.11
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3775.11 / b3775.7a
- Title
- Upgrade the wavetrap at Dumont substation to increase the rating of the Stillwell-Dumont 345 kV line to match conductor rating.
- Description
- Upgrade the wavetrap at Dumont substation to increase the rating of the Stillwell-Dumont 345 kV line to match conductor rating.
- Cost Information
- Time Estimate
- Dec 01 2026
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 05DUMONT-17STILLWELL 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.7
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3775.7 / b3775.7b
- Title
- Upgrade breakers at Dumont substation on the Stillwell-Dumont 345 kV line.
- Description
- Upgrade the limiting element at Dumont substation to increase the rating of the Stillwell-Dumont 345 kV line to match conductor rating. This includes replacement of breakers F and F1.
- Cost Information
- Time Estimate
- Dec 01 2026
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 05DUMONT-17STILLWELL 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.1
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- b3775.1
- Title
- Swap the NIPSCO Green Acre Tap towers from the St. John-Green Acres-Olive 345 kV line
- Description
- Outside of the Green Acres substation, swap the NIPSCO Green Acre Tap towers from the St. John-Green Acres-Olive 345 kV line to the University Park N-Olive 345 kV line to create a University Park N-Green Acres-Olive and St. John-Olive 345 kV lines.
- Cost Information
- Time Estimate
- Mar 30 2027
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 17STJOHN-CRETE EC ;BP 345.0 kV Ckt 1 line | (Any) |
| ||||||||||
| 05OLIVE-AF2-359 TP 345.0 kV Ckt 1 line | (Any) |
| ||||||||||
| UNIV PK N;RP-AF2-359 TP 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.10
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3775.10
- Title
- Perform sag study mitigation work on Olive – University Park
- Description
- Perform a sag study on the Olive – University Park 345kV line to increase the operating temperature to 225 F. Remediation work includes two tower replacements on the line.
- Cost Information
- Time Estimate
- Dec 01 2026
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| UNIV PK N;RP-AF2-359 TP 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.2
- Type
- Load Flow
- TO
- NextEra
- RTEP ID / TO ID
- b3775.2
- Title
- Reconductor NEET’s section of Crete(IN/IL border)-St. John 345 kV line (6.95 miles).
- Description
- Reconductor NEET’s section of Crete(IN/IL border)-St. John 345 kV line (6.95 miles).
- Cost Information
- Time Estimate
- May 09 2023
Not Contingent Note: AF1-296 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AF1-296 is not contingent on this baseline upgrade as it is already in-service.
| Facility | Contingency | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 17STJOHN-CRETE EC ;BP 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.3
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- b3775.3
- Title
- Rebuild ComEd’s section of 345 kV double circuit in IL from St. John to Crete
- Description
- Part of b3775 baseline. Rebuild ComEd’s section of 345 kV double circuit in IL from St. John to Crete (5 miles) with twin bundled 1277 ACAR conductor.
- Cost Information
- Time Estimate
- Dec 01 2026
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 17STJOHN-CRETE EC ;BP 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: b3775.5
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- b3775.5
- Title
- Replace E. Frankfort 345 kV circuit breaker “9-14” with 3150A SF6 circuit breaker.
- Description
- Part of b3775 baseline. Replace E. Frankfort 345 kV circuit breaker “9-14” with 3150A SF6 circuit breaker.
- Cost Information
- Time Estimate
- TBD
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | (Any) |
|
System Reinforcement: s3011
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- s3011 / CE_S3011
- Title
- Replace 345kV straight bus at TSS 116 Goodings Grove with a gas insulated switchgear ("GIS") breaker and a half configuration.
- Description
- Replace 345 kV open air straight bus with GIS in a breaker and half configuration (34 Circuit Breakers) at Goodings Grove with 80kA capability.
- Cost Information
- Time Estimate
- Dec 31 2028
Not Contingent Note: AF1-296 contributes to the loading of an overloaded facility that is being mitigated by a planned supplemental project. AF1-296 is not contingent on this supplemental project as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| (Any) | COMED_P4_116-45-L11614__SRT-A | No new ratings for this Flowgate. | |
| (Any) | COMED_P4-6_116-345-R______SRT-A | No new ratings for this Flowgate. | |
| (Any) | COMED_P4_112-45-BT4-5___SRT-A | No new ratings for this Flowgate. |
System Reinforcement: n5145
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- n5145
- Title
- Reconfigure Wilton 765kV bus
- Description
- Reconfigure Wilton 765kV bus thereby allowing for 765kV L11216 (currently on Bus 6) to be relocated to Bus 8. Along with this line relocation, installation of 2-765kV BT CBs (6-8 & 8-2). Cost increased from $12M to $55M. This will eliminate the stuck breaker contingencies '112-65-BT4-5__' and '112-65-BT5-6__'. No other contingency updates needed.
- Total Cost ($USD)
- $55,229,373
- Discounted Total Cost ($USD)
- $55,229,373
- Allocated Cost ($USD)
- $0
- Time Estimate
- Dec 31 2025
Contingent Note: Based on PJM cost allocation criteria, AF1-296 does not receive cost allocation towards this upgrade which has been securitized by a prior Queue/Cycle. Although AF1-296 may not have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable for the reliability to the PJM system. If AF1-296 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 | ||
|---|---|---|---|
| (Any) | COMED_P4_112-65-BT4-5___SRT-A | No new ratings for this Flowgate. |
System Reinforcement: b3775.4
- Type
- Load Flow
- TO
- ComEd
- RTEP ID / TO ID
- b3775.4 / CE_B3775.4
- Title
- Rebuild 345 kV double circuit extending from Crete to E. Frankfort.
- Description
- Part of b3775 baseline. Rebuild 12.7 miles of 345 kV double circuit extending from Crete to E. Frankfort with twin bundled 1277 ACAR conductor.
- Cost Information
- Time Estimate
- Dec 01 2026
Contingent Note: Although AF1-296 may not presently have cost responsibility for this upgrade, AF1-296 may need this upgrade in-service to be deliverable to the PJM system. If AF1-296 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 | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Any) | 765-L11215__-S_SRT-A | No new ratings for this Flowgate. | ||||||||||||||||
| E FRANKFO; B-CRETE EC ;BP 345.0 kV Ckt 1 line | (Any) |
|
Attachments
AF1-296 One Line Diagram
