AG1-378 Final System Impact Study (Retool 2) Report
v2.00 released 2026-05-14 11:56
Philipsburg 115 kV
6.0 MW Capacity / 20.0 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 CE-Black Moshannon OZ LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Mid-Atlantic Interstate Transmission, LLC.
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- Conduct any remaining analyses or updated analyses based on New Service Requests withdrawn during Decision Point III (DP3); and
- Adjust the security obligation based on New Service Requests withdrawn during Decision Point III and/or during the Final Agreement Negotiation Phase.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 projects moving on in the Final Agreement Negotiation Phase (Removes DP3 withdrawals).
- The Final System Impact Study reflecting results from the retooled analysis (Retool 1) will be publicly available on PJM’s website; Project Developers and Eligible Customers must obtain the results from the website.
- PJM will provide updated final electronic agreements to Project Developers and Eligible Customers in the Cycle reflecting updates from the Final System Impact Study after Retool 1 including the adjusted Security requirements.
The AG1-378 Final System Impact Study (Retool 1) Report is available for download here.
Retool 2 (if needed):
If particular New Service Requests do not sign their final agreements after receiving the updated information after Retool 1, there may be the need to run a second retool (Retool 2) to identify if any network upgrades are no longer necessary:
- PJM will perform Retool 2 (if necessary) considering only the removal of projects from the model which chose not to execute their agreements after Retool 1.
- The updated Final System Impact Study reflecting results from Retool 2 will be publicly available on PJM’s website; Project Developers and Eligible Customers must obtain the results from the website.
- If there are any adjustments to the agreements required after Retool 2, the necessary network upgrade or Security changes will be handled via the scope change process post-GIA.
General
The Project Developer has proposed an uprate to a planned/existing Solar/Storage facility located in the Mid-Atlantic Interstate Transmission, LLC zone — Centre County, Pennsylvania. This project is an increase to the developer’s AG1-090/AG1-377 project(s), which will share the same Point of Interconnection. The AG1-378 project is a 20.0 MW uprate (6.0 MW Capacity uprate) to the previous project(s). The total installed facilities will have a capability of 135.0 MW with 42.0 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
The interconnection of the project at the Primary POI will be accomplished by installing one 115 kV breaker at Philipsburg Substation to expand the station from a four breaker to a five breaker ring bus. AG1-090, AG1-377, and AG1-378 are behind the same POI. All three projects are in Transition Cycle 1 and will share costs for the required Transmission Owner Interconnection Facilities and physical interconnection network upgrades.
Attachment 1 shows a one-line diagram of the proposed interconnection facilities for the AG1-378 generation project to connect to the transmission system.
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 AG1-378 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 AG1-378 | Cost Subject to Security* | |
| Transmission Owner Interconnection Facilities (TOIF) | $84,934 | $84,934 | |
| Other Scope | $1,658 | $1,658 | |
| Option To Build Oversight | $0 | $0 | |
| Physical Interconnection Network Upgrades | |||
| Stand Alone Network Upgrades | $0 | $0 | |
| Network Upgrades | $1,099,479 | $1,099,479 | |
| System Reliability Network Upgrades | |||
| Steady State Thermal & Voltage (SP & LL) | $3,082,635 | $3,082,635 | |
| Transient Stability | $0 | $0 | |
| Short Circuit | $0 | $0 | |
| Transmission Owner Analysis | |||
| SubRegional | $0 | $0 | |
| Distribution | $0 | $0 | |
| Affected System Reinforcements | |||
| AFS - PJM Violations | $0 | $0 | |
| AFS - Non-PJM Violations | $0 ** | $0 ** | |
| Total | $4,268,705 | $4,268,705 | |
* Contributes to calculation for Security. See Security Requirement Section of this report for additional detail.
** This value reflects the results at the time of the report posting and it is subject to change. AFS – Non-PJM Violations are not subject to Security. For latest AFS – Non-PJM Violations, please refer to the latest Affected System Study Report for your project.
Definitions
Transmission Owner Interconnection Facilities: Facilities that are owned, controlled, operated and maintained by the Transmission Owner on the Transmission Owner’s side of the Point of Change of Ownership to the Point of Interconnection, including any modifications, additions or upgrades made to such facilities and equipment, that are necessary to physically and electrically interconnect the Generating Facility with the Transmission System or interconnected distribution facilities.
Stand Alone Network Upgrades: Network Upgrades, which are not part of an Affected System, which a Project Developer may construct without affecting day-to-day operations (e.g. taking a transmission outage) of the Transmission System during their construction.
Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider’s overall Transmission System for the general benefit of all users of such Transmission System. Network Upgrades have no impact or potential impact on the Transmission System until the final tie-in is complete.
Notes
Note 1: PJM Open Access Transmission Tariff (OATT), Part VII, Subpart D, section 307.5 outlines cost allocation rules. The rules are further clarified in PJM Manual 14H, section 4.2.6. PJM shall identify the New Service Requests in the Cycle contributing to the need for the required Network Upgrades within the Cycle. All New Service Requests that contribute to the need for a Network Upgrade will receive cost allocation for that upgrade pursuant to each New Service Request’s contribution to the reliability violation identified on the transmission system in accordance with PJM Manuals.
Note 2: There will be no inter-Cycle cost allocation for Interconnection Facilities or Network Upgrades identified in the System Impact Study costs identified in a Cycle; all such costs shall be allocated to New Service Requests in that Cycle.
Note 3: For Project Developers with System Reinforcements listed: If this project presents cost allocation to a System Reinforcement indicates $0, then please be aware that as changes to the interconnection process occur, the cost responsibilities can change and a cost allocation may be assigned to this project. In addition, although this project presents cost allocation to a System Reinforcement is presently $0, this project may need this system reinforcement completed to be deliverable to the PJM system. If this project desires to come into service prior to completion of the system reinforcement, the Project Developer will need to request PJM to perform an interim deliverability study to determine if they would be deliverable for all or a portion of their output for each delivery year until the system reinforcement is complete.
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 AG1-090/AG1-377/AG1-378
Security has been calculated for the AG1-090/AG1-377/AG1-378 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 AG1-090/AG1-377/AG1-378
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 interconnection of the project at the Primary POI will be accomplished by installing one 115 kV breaker at Philipsburg Substation to expand the station from a four breaker to a five breaker ring bus. AG1-090, AG1-377, and AG1-378 are behind the same POI. All three projects are in Transition Cycle 1 and will share costs for the required Transmission Owner Interconnection Facilities and physical interconnection network upgrades. Philipsburg Substation is planned to be converted to a four breaker ring bus with supplemental project s1919. Changes, deferral, or cancelation of this supplemental project could result in additional scope for AG1-090/AG1-377/AG1-378 to interconnect at Philipsburg Substation.
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 | ||||
| n9617.0 | Install a new 115 kV breaker and associated controls direct connection of AG1-090/AG1-377/AG1-378 Generating Facility to the existing Philipsburg Substation. | $1,334,522 | $408,830 | $24,155 | $4,444 | $1,771,951 | $590,650 (See Note 1) |
| n9616.0 | Install carrier equipment at Shawville Substation. | $704,108 | $63,203 | $12,744 | $442 | $780,497 | $260,166 (See Note 1) |
| n9615.0 | Install carrier equipment at Eagle Valley Substation. | $679,882 | $53,426 | $12,306 | $374 | $745,988 | $248,663 (See Note 1) |
| Other | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) | Support for Project Developer-owned revenue metering. | $3,730 | $0 | $1,243 | $0 | $4,973 | $1,658 (See Note 1) |
| Transmission Owner Interconnection Facilities | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) | Philipsburg Substation Expansion – New 115kV Generator Tie Line Terminal: Construct one span of 115kV conductor from Philipsburg Substation to the Project Developer-owned dead-end structure outside the substation. | $183,511 | $6,813 | $3,322 | $1,499 | $195,145 | $65,048 (See Note 1) |
| (Pending) | Energize and integrate generator interconnection facilities to the Transmission System. | $58,509 | $0 | $1,149 | $0 | $59,658 | $19,886 (See Note 1) |
Based on the scope of work for the Interconnection Facilities, it is expected to take 35 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.
Note 1: A Common Use Upgrade is a Network Upgrade that is needed for the interconnection of Generating Facilities or Merchant Transmission Facilities of more than one Project Developer or Eligible Customer and which is the shared responsibility of each Project Developer or Eligible Customer. If multiple Project Developers request to connect to the same interconnection substation, the Transmission Owner will determine the cost to accommodate all the requests at the substation. The cost for the interconnection will be allocated in proportion to the number of required terminations into the substation.
Transmission Owner Analysis
TO performed an analysis of its underlying transmission system <100 kV system. New Service Request Project AG1-378 did not contribute to any overloads on the TO transmission <100 kV system.
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. FirstEnergy 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 solar generation facility shall provide the Transmission Provider with site-specific meteorological data including:Transmission Owner Requirements
- Temperature (degrees Fahrenheit)
- Atmospheric Pressure (hectopascals)
- Irradiance
- Forced outage data
The Project Developer will be required to comply with all interconnected Transmission Owner’s revenue metering requirements located at the following link: PJM - Transmission Owner Engineering & Construction Standards.
Summer Peak Analysis
The New Service Request AG1-378 was evaluated as a 20.0 MW (6.0 MW Capacity) injection in the PENELEC 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 | PENELEC | 26HOMER CT-26SHELOCTA 230.0 kV Ckt 1 line | PN_P2-3_PN-230-0347-2_SRT-A | Breaker | AC | 111.13 % | 980.0 | B | 1089.05 | 3.81 | |
| GD1 | PENELEC | 26HOMER CT-26SHELOCTA 230.0 kV Ckt 1 line | PN_P2-3_PN-230-0347-A_SRT-A | Breaker | AC | 108.13 % | 980.0 | B | 1059.68 | 3.61 | |
| GD1 | PENELEC | 26SHAWVL 1-26SHAWVL 1 115.0/230.0 kV Ckt 1A transformer | PN_P2-2_PN-230-014T_SRT-A | Bus | AC | 104.41 % | 201.0 | B | 209.87 | 6.35 | |
| GD1 | PENELEC | 26SHELOCTA-26KEYSTONE 230.0 kV Ckt 1 line | PN_P2-3_PN-230-0347-2_SRT-A | Breaker | AC | 100.58 % | 980.0 | B | 985.72 | 4.44 |
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.)
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 | AP/PENELEC | 26BLAIRSVL-01SOCIAL 138.0 kV Ckt 1 line | PN_P1-2_PN-230-038_SRT-A | OP | AC | 110.37 % | 294.0 | B | 324.48 | 1.34 | |
| GD1 | PENELEC | 26CANYON-26N.MESHPN 230.0 kV Ckt 1 line | Base Case | OP | AC | 100.84 % | 546.0 | A | 550.59 | 1.54 | |
| GD1 | PENELEC | 26E.TWANDA-26CANYON 230.0 kV Ckt 1 line | Base Case | OP | AC | 102.24 % | 546.0 | A | 558.22 | 1.54 | |
| GD1 | PENELEC | 26EAGL VAL-26TYRONE N 115.0 kV Ckt 1 line | PN_P1-2_PN-115-050_SRT-A | OP | AC | 116.27 % | 245.0 | B | 284.87 | 20.0 | |
| GD1 | PENELEC | 26HOMER CT-26SHELOCTA 230.0 kV Ckt 1 line | Base Case | OP | AC | 104.61 % | 809.0 | A | 846.29 | 2.76 | |
| GD1 | PENELEC | 26PHILIPSB-26SHAW. 2 115.0 kV Ckt 1 line | PN_P1-2_PN-115-052A_SRT-A | OP | AC | 139.29 % | 202.0 | B | 281.37 | 20.0 |
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 | PENELEC | 26E.TWANDA-26CANYON 230.0 kV Ckt 1 line | PL_02_P12_001029_SRT-A | OP | AC | 100.31 % | 666.0 | B | 668.03 | 1.53 |
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 AG1-378 was evaluated as a 20.0 MW injection in the PENELEC 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.
(No flowgates were eliminated after considering the topology reinforcements required by the cycle.)
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.
(No impacts were found for this analysis)
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
New Service Request projects in PJM Transition Cycle 1, Cluster 71 are listed in Table 1 below. The report covers the dynamic analysis of the Cluster 71 projects.
The analysis is effectively a screening study to determine whether the addition of the Cluster 71 projects meet the dynamics requirements of the NERC, First Energy (FE), 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 71 projects were dispatched online at maximum power output, with approximately unity power factor at the high side of the GSUs, 1.02 pu voltage at the generator terminals, and 1.02 pu voltage at the POI bus for AG1-090, AG1-377, and AG1-378.
Cluster 71 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 101 contingencies were studied, each with a 20 second simulation time period (with 1.0 second initial run prior to any events). Studied faults included:
a) Steady-state operation (Category P0);
b) Three-phase faults with normal clearing time (Category P1);
c) Single-phase faults with stuck breaker (Category P4);
d) Single phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure (Category P5).
No multiple-circuit tower line faults were identified for this study.
High Speed Reclosing (HSR) facilities were found in the vicinity of TC1 Cluster 71 projects.
For all simulations, the projects under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance. For all of the fault contingencies tested on the 2027 peak load case:
a) Cluster 71 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
b) The system with Cluster 71 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.
No mitigation is required for TC1 Cluster 71.
Table 1: TC1 Cluster 71 Projects
Cluster | Project | Fuel Type | Transmission Owner | MFO | MWE | MWC | Point of Interconnection |
71 | AG1-090 | Solar + Storage | FirstEnergy (FE) Transmission System, Pennsylvania Electric Company (PENELEC) zone | 95 MW | 95 MW | 30 MW | Philipsburg 115 kV Substation |
AG1-377 | Solar | FirstEnergy (FE) Transmission System, Pennsylvania Electric Company (PENELEC) zone | 20 MW | 20 MW | 6 MW | Philipsburg 115 kV Substation | |
AG1-378 | Solar | FirstEnergy (FE) Transmission System, Pennsylvania Electric Company (PENELEC) zone | 20 MW | 20 MW | 6 MW | Philipsburg 115 kV Substation |
Reactive Power Analysis
The reactive power capability of AG1-378 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 |
| AC1-025 | Dale Summit | In Service |
| AE2-001 | Nittany-Zion 46 kV | Suspended |
| AE2-074 | Potter 46 kV | Under Construction |
| AE2-113 | Farmers Valley-Ridgeway 115 kV | Under Construction |
| AE2-117 | ABW Tap-Alexandria 46 kV | Suspended |
| AE2-118 | ABW Tap-Williamsburg 46 kV | Engineering & Procurement |
| AE2-126 | Dubois-Curwensville 34.5 kV | In Service |
| AE2-129 | Philipsburg-Clarence 34.5 kV | In Service |
| AE2-131 | Philipsburg-Karthaus 34.5 | Under Construction |
| AE2-139 | East Towanda-Grover 230 kV | Engineering & Procurement |
| AE2-224 | Bear Rock-Johnstown 230 kV | In Service |
| AE2-248 | Fillmore-Thompson Farm 46 kV | Suspended |
| AE2-262 | Moshannon-Milesburg 230 kV | Engineering & Procurement |
| AE2-263 | Moshannon-Milesburg 230 kV II | Engineering & Procurement |
| AE2-299 | Erie East 230 kV | Suspended |
| AE2-316 | Brookville-Squab Hollow 138 kV | Under Construction |
| AE2-344 | Edinboro South-Venango Junction 115 kV | Withdrawn |
| AF1-006 | Fairview East 34.5 kV | In Service |
| AF1-039 | Listonburg-Highpoint 24.9 kV | In Service |
| AF1-086 | Madera-Westover South 115 kV | Under Construction |
| AF1-094 | Union City-Cambridge Springs 34.5 kV | Engineering & Procurement |
| AF1-098 | Four Mile Jct-Corry East 115 kV | Suspended |
| AF1-134 | Philipsburg-Madera 34.5 kV | Under Construction |
| AF1-140 | Claysburg 23 kV | Engineering & Procurement |
| AF1-143 | Lick Run 115 kV | Engineering & Procurement |
| AF1-153 | Motion-Ridgeway 46 kV | Suspended |
| AF1-167 | West Freedom-C&K Coal 25 kV | Suspended |
| AF1-272 | Lucerne 115 kV | Engineering & Procurement |
| AF1-287 | Edinboro South 34.5 kV II | Withdrawn |
| AF1-302 | Brookville-Squab Hollow 138 kV | Under Construction |
| AF1-321 | Hooversville 115 kV I | Suspended |
| AF2-001 | Hooversville 115 kV II | Suspended |
| AF2-002 | Hooversville 115 kV III | Suspended |
| AF2-039 | Shawville-Clearfield 34.5 kV | Under Construction |
| AF2-050 | Bear Rock-Johnstown 230 kV | Engineering & Procurement |
| AF2-088 | Shawville-Clearfield 34.5 kV II | Under Construction |
| AF2-092 | Snake Spring-Bedford Area 23 kV | Withdrawn |
| AF2-130 | Cobalt Corners 34.5 kV | In Service |
| AF2-165 | Clark Summit-Emlenton 34.5 kV | In Service |
| AF2-221 | Scalp Level 22.9 kV | Suspended |
| AF2-238 | Mansfield-South Troy 34.5 kV | Engineering & Procurement |
| AF2-294 | Thompson 34.5 kV | Suspended |
| AF2-296 | Madera 34.5 kV | Engineering & Procurement |
| AG1-040 | Morgan Street-Mount Hope 34.5 kV | Engineering & Procurement |
| AG1-090 | Philipsburg 115 kV | Engineering & Procurement |
| AG1-100 | Venango-Saegertown 34.5 kV | Engineering & Procurement |
| AG1-140 | Union City 34.5 kV | Suspended |
| AG1-193 | Utica Junction 34.5 kV | Withdrawn |
| AG1-197 | Morgan Street-Cochranton 34.5 kV | Suspended |
| AG1-198 | Union City 34.5 kV | In Service |
| AG1-253 | Erie East-Union City 34.5 kV | Suspended |
| AG1-281 | Claysburg-HCR Tap 46 kV | Engineering & Procurement |
| AG1-301 | Miller REC-Warrior Ridge 46 kV | Withdrawn |
| AG1-377 | Philipsburg 115 kV | Engineering & Procurement |
| AG1-548 | Erie South-Union City 115 kV | Engineering & Procurement |
| V3-030 | St. Benedict-Patton 46kV | In Service |
| Y1-033 | Penn Mar-Rock Wood 115kV | In Service |
| Z1-069 | Gold-Sabinsville 115kV | 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.
Affected System - Non-PJM Identified Violations
In coordination with other Affected System Operators, PJM has determined that the Affected System Operator for this project that requires an Affected System Study. For the latest Affected System Study results pertaining this project, please refer to your Affected System Study report by the Affected System Operator. If the Affected System Operator identified the need for a system reinforcement on their system due to their planning criteria, Project Developer must follow the Affected System Operator Tariff for construction of the network upgrade. PJM lists any required network upgrades identified by the Affected System Operator in the PJM Project Developer’s GIA under Schedule F.
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: n9116.0
- Type
- Load Flow
- TO
- PENELEC
- RTEP ID / TO ID
- n9116.0 / TC1-PN-001.d
- Title
- Rebuild approximately 11 miles of the Homer City-Shelocta 230 kV line with double bundled 795 kcmil 26/7 ACSS conductor
- Description
- Rebuild the Homer City – Shelocta 230 kV Line, approximately 11 miles, with double bunded 795 kcmil 26/7 ACSS conductor. Terminate new conductor at Homer City substation. Terminate new conductor at Shelocta substation.
- Total Cost ($USD)
- $39,312,233
- Discounted Total Cost ($USD)
- $39,312,233
- Allocated Cost ($USD)
- $2,451,189
- Time Estimate
- 31 Months
Contributor
| Facility | Contingency | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 26HOMER CT-26SHELOCTA 230.0 kV Ckt 1 line | (Any) |
|
| Project | MW Impact | Percent Allocation | Allocated Cost ($USD) |
|---|---|---|---|
| AF2-050 | 14.7 MW | 24.0% | $9,442,830 |
| AG1-090 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 18.1 MW | 29.6% | $11,641,379 |
| AG1-377 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 3.8 MW | 6.2% | $2,451,189 |
| AG1-378 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 3.8 MW | 6.2% | $2,451,189 |
| AG1-548 | 20.7 MW | 33.9% | $13,325,647 |
System Reinforcement: n9119.0
- Type
- Load Flow
- TO
- PENELEC
- RTEP ID / TO ID
- n9119.0 / TC1-PN-003.b
- Title
- Reconductor/Rebuild the Shelocta – Keystone 230 kV Line, approximately 2.5 miles, with 1272 kcmil 45/7 ACSR 2-conductor
- Description
- Reconductor/Rebuild the Shelocta – Keystone 230 kV Line, approximately 2.5 miles, with 1272 kcmil 45/7 ACSR 2-conductor. Terminate new conductor at Keystone substation. Terminate new conductor at Shelocta substation.
- Total Cost ($USD)
- $9,533,592
- Discounted Total Cost ($USD)
- $9,533,592
- Allocated Cost ($USD)
- $624,739
- Time Estimate
- 23 Months
Contributor
| Facility | Contingency | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 26SHELOCTA-26KEYSTONE 230.0 kV Ckt 1 line | (Any) |
|
| Project | MW Impact | Percent Allocation | Allocated Cost ($USD) |
|---|---|---|---|
| AF2-050 | 15.1 MW | 22.3% | $2,124,309 |
| AG1-090 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 21.1 MW | 31.1% | $2,967,790 |
| AG1-377 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 4.4 MW | 6.6% | $624,739 |
| AG1-378 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 4.4 MW | 6.6% | $624,739 |
| AG1-548 | 22.7 MW | 33.5% | $3,192,016 |
System Reinforcement: n9225.0
- Type
- Load Flow
- TO
- PENELEC
- RTEP ID / TO ID
- n9225.0 / TC1-PN-001.e
- Title
- Replace 230 kV substation conductor and line drops at Shelocta substation for the Homer City-Shelocta 230 kV line terminal
- Description
- Replace 230 kV substation conductor and line drops at Shelocta substation for the Homer City-Shelocta 230 kV line terminal
- Total Cost ($USD)
- $107,569
- Discounted Total Cost ($USD)
- $107,569
- Allocated Cost ($USD)
- $6,707
- Time Estimate
- 13 Months
Contributor
| Facility | Contingency | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 26HOMER CT-26SHELOCTA 230.0 kV Ckt 1 line | (Any) |
|
| Project | MW Impact | Percent Allocation | Allocated Cost ($USD) |
|---|---|---|---|
| AF2-050 | 14.7 MW | 24.0% | $25,838 |
| AG1-090 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 18.1 MW | 29.6% | $31,854 |
| AG1-377 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 3.8 MW | 6.2% | $6,707 |
| AG1-378 ⧉ Philipsburg 115kV yard - Penelec: 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: AG1-090, AG1-377, AG1-378 | 3.8 MW | 6.2% | $6,707 |
| AG1-548 | 20.7 MW | 33.9% | $36,463 |
System Reinforcement: s3334.1
- Type
- Load Flow
- TO
- PENELEC
- RTEP ID / TO ID
- s3334.1 / PN-2023-030
- Title
- Replace the existing Shawville 1A Transformer
- Description
- Replace the existing Shawville 1A Transformer with a 3-winding, 230/115-17.2kV, 180/240/300 MVA transformer. Install a 17.2 kV circuit breaker. Replace disconnect switches, bus conductor, insulators, surge arresters, and the 230 kV breaker. Transformer will be limited by relay panels owned by FE and the Plant.
- Cost Information
- Time Estimate
- Jun 30 2027
Contingent Note: Although AG1-378 may not presently have cost responsibility for this upgrade, AG1-378 may need this upgrade in-service to be deliverable to the PJM system. If AG1-378 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 26SHAWVL 1-26SHAWVL 1 230.0/115.0 kV Ckt 1A transformer | (Any) |
|
Attachments
AG1-378 One Line Diagram
