AF1-128 Final System Impact Study (Retool 2) Report
v2.00 released 2026-05-14 11:46
Chesterfield 230 kV
569.0 MW Capacity / 569.0 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 Virginia Electric and Power Company (d/b/a Dominion Energy Virginia), and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Virginia Electric and Power Company (d/b/a Dominion Energy Virginia).
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- Conduct any remaining analyses or updated analyses based on New Service Requests withdrawn during Decision Point III (DP3); and
- Adjust the security obligation based on New Service Requests withdrawn during Decision Point III and/or during the Final Agreement Negotiation Phase.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 AF1-128 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 a Natural Gas generating facility located in the Virginia Electric and Power Company (d/b/a Dominion Energy Virginia) zone — Chesterfield County, Virginia. The installed facilities will have a total capability of 569.0 MW with 569.0 MW of this output being recognized by PJM as Capacity.Project Information
Capacity Interconnection Rights (CIR) Transfer Details
This project intends to claim and transfer CIRs from the following Deactivation capacity generation resources. PJM performed a reliability analysis of the impacts to the system capability for the proposed transfer of CIRs from the Deactivation generation resources.
| Unit Name | Status | CIR Claimed | POI Transfer |
|---|---|---|---|
| Chesterfield 3 | Deactivated Generator | 100.0 | Yes |
| Chesterfield 4 | Deactivated Generator | 119.0 | Yes |
| Chesterfield 5 | Deactivated Generator | 350.0 | No |
Physical Interconnection Facility Study
The transmission owner has completed the Physical Interconnection Facilities Study. This report is available for download.
Point of Interconnection
AF1-128 will interconnect on the Dominion transmission system via a direct connection at the existing 230 kV Chesterfield Power Station.
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 AF1-128 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 AF1-128 | Cost Subject to Security* | |
| Transmission Owner Interconnection Facilities (TOIF) | $853,497 | $853,497 | |
| Other Scope | $0 | $0 | |
| Option To Build Oversight | $0 | $0 | |
| Physical Interconnection Network Upgrades | |||
| Stand Alone Network Upgrades | $0 | $0 | |
| Network Upgrades | $2,182,499 | $2,182,499 | |
| System Reliability Network Upgrades | |||
| Steady State Thermal & Voltage (SP & LL) | $0 | $0 | |
| 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 | $3,035,996 | $3,035,996 | |
* 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 AF1-128
Security has been calculated for the AF1-128 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 AF1-128
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 New Service Request Project will interconnect with the Dominion transmission system via a direct connect to the Chesterfield 230 kV Sub. The required work for the interconnection of the New Service Request Project to the Dominion Transmission System is detailed in the following tables.
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 | ||||
| n8282 | Expansion of Existing Chesterfield Substation | $1,436,190 | $583,876 | $117,227 | $45,206 | $2,182,499 | $2,182,499 |
| Transmission Owner Interconnection Facilities | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) | Transmission Owner Interconnection Facilities, including one (1) 230 kV backbone structure and foundation outside the fence of the interconnection substation will be constructed to terminate the Project Developer’s generator lead line. There will also be a line conductor constructed from the backbone structure to the bus position in the switchyard of the interconnection substation. | $559,966 | $231,352 | $48,497 | $13,682 | $853,497 | $853,497 |
Based on the scope of work for the Interconnection Facilities, it is expected to take 21 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.
It is estimated to take 21 months to complete this work upon execution of the Generator Interconnection Agreement (GIA).This estimated time to complete is dependent on major equipment lead times. These preliminary cost estimates are based on typical engineering costs. A more detailed engineering cost estimates are normally done when the Project Developer provides an exact site plan location for the generation substation during a future study phase.
Note that the TO findings were made from a conceptual review of this project. A more detailed review of the connection facilities and their cost will be identified in a future study phase. Further note that the cost estimate data provided should be considered high level estimates since it was produced without a detailed engineering review. The Project Developer will be responsible for the actual cost of construction. TO herein reserves the right to return to any issues in this document and, upon appropriate justification, request additional monies to complete any reinforcements to the transmission systems.
Remote Terminal Work: During Phase 2 of the PJM interconnection process, TO’s System Protection Engineering Department will review transmission line protection as well as anti-islanding required to accommodate the new generation and interconnection substation. System Protection Engineering will determine the minimal acceptable protection requirements to reliably interconnect the proposed generating facility with the transmission system. The review is based on maintaining system reliability by reviewing TO’s protection requirements with the known transmission system configuration which includes generating facilities in the area. This review may determine that transmission line protection and communication upgrades are required at remote substations.
Transmission Owner Analysis
PJM performed a power flow analysis of the transmission system using a 2027 load flow model and the results were verified by Dominion.
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. Dominion 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.Transmission Owner Requirements
The Project Developer will be required to comply with all interconnected Transmission Owner’s revenue metering requirements located at the following link: PJM - Transmission Owner Engineering & Construction Standards.
Summer Peak Analysis
The New Service Request AF1-128 was evaluated as a 219.0 MW (569.0 MW Capacity) injection in the Dominion 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 | DVP | 8CHCKAHM-8ELMONT 500.0 kV Ckt 1 line | DVP_P4-2: 563T576_SRT-S | Breaker | AC | 104.31 % | 3637.0 | C | 3793.65 | 50.14 |
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 | DVP | 6AQUI_HARB_B-6GARSVL 230.0 kV Ckt 1 line | DVP_P1-2: LN 2157_SRT-A | OP | AC | 100.58 % | 898.64 | B | 903.81 | 13.0 | |
| GD1 | DVP | 6CHCKAHM-8CHCKAHM 230.0/500.0 kV Ckt 1 transformer | DVP_P1-2: LN 567_SRT-A | OP | AC | 117.56 % | 934.92 | B | 1099.11 | 38.59 | |
| GD1 | DVP | 6CHESTF A-6IRON208 230.0 kV Ckt 1 line | DVP_P1-2: LN 557_SRT-S | OP | AC | 119.65 % | 663.64 | B | 794.05 | 49.91 | |
| GD1 | DVP | 6ELMONT-8ELMONT 230.0/500.0 kV Ckt 2 transformer | DVP_P1-2: LN 557_SRT-S | OP | AC | 108.08 % | 879.84 | B | 950.89 | 29.9 | |
| GD1 | DVP | 6FREDBRG-6CRANES 230.0 kV Ckt 1 line | DVP_P1-2: LN 9296_SRT-A | OP | AC | 103.41 % | 984.18 | B | 1017.75 | 14.2 | |
| GD1 | DVP | 6IRON208-6SOUWEST 230.0 kV Ckt 1 line | DVP_P1-2: LN 557_SRT-S | OP | AC | 110.61 % | 663.64 | B | 734.04 | 49.89 | |
| GD1 | DVP | 6LADYSMITH-8LADYSMITH 230.0/500.0 kV Ckt 2 transformer | DVP_P1-2: LN 574_SRT-S_SENS | OP | AC | 103.88 % | 889.43 | B | 923.97 | 17.65 | |
| GD1 | DVP | 6NRTHEST-6ELMONT 230.0 kV Ckt 1 line | DVP_P1-2: LN 557_SRT-S | OP | AC | 117.46 % | 678.68 | B | 797.16 | 21.02 | |
| GD1 | DVP | 8CHCKAHM-8ELMONT 500.0 kV Ckt 1 line | DVP_P1-2: LN 563_SRT-S-1 | OP | AC | 136.2 % | 2442.12 | B | 3326.15 | 45.64 | |
| GD1 | DVP | 8ELMONT-8LADYSMITH 500.0 kV Ckt 1 line | DVP_P1-2: LN 576_SRT-A | OP | AC | 115.81 % | 4070.2 | B | 4713.58 | 67.28 | |
| GD1 | DVP | 8LADYSMITH-8KRAKEN 500.0 kV Ckt 1 line | DVP_P1-2: LN 581_SRT-S | OP | AC | 113.6 % | 3220.44 | B | 3658.55 | 48.57 | |
| GD1 | DVP | 8SPOTSYL-8MORRSVL 500.0 kV Ckt 1 line | DVP_P1-2: LN 552_SRT-S | OP | AC | 105.29 % | 3220.44 | B | 3390.96 | 37.24 |
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 | DVP | 6FOUR RIVERS-6STJOHN 230.0 kV Ckt 1 line | DVP_P1-2: LN 574_SRT-S | OP | AC | 128.71 % | 1123.3 | B | 1445.82 | 24.66 | |
| GD1 | DVP | 6MDLTHAN-8MDLTHAN 230.0/500.0 kV Ckt 1 transformer | DVP_P1-2: LN 563_SRT-S-1 | OP | AC | 111.78 % | 1058.16 | B | 1182.76 | 24.68 | |
| GD1 | DVP | 6STJOHN-AE1-157 TP 230.0 kV Ckt 1 line | DVP_P1-2: LN 574_SRT-S | OP | AC | 121.31 % | 1123.3 | B | 1362.65 | 24.66 | |
| GD1 | DVP | 8CHANCE-8BRISTER 500.0 kV Ckt 1 line | DVP_P1-2: LN 594_SRT-S | OP | AC | 103.49 % | 4070.2 | B | 4212.31 | 43.93 | |
| GD1 | DVP | 8CHCKAHM-8ELMONT 500.0 kV Ckt 1 line | Base Case | OP | AC | 104.09 % | 2442.12 | A | 2541.99 | 41.73 | |
| GD1 | DVP | 8LADYSMITH-8CHANCE 500.0 kV Ckt 1 line | DVP_P1-2: LN 573_SRT-A | OP | AC | 103.53 % | 4070.2 | B | 4213.9 | 44.83 | |
| GD1 | DVP | 8MORRSVL-8LOUDOUN 500.0 kV Ckt 1 line | DVP_P1-2: LN 568_SRT-S | OP | AC | 113.01 % | 3220.44 | B | 3639.35 | 24.87 | |
| GD1 | DVP | 8NO ANNA-8SPOTSYL 500.0 kV Ckt 1 line | DVP_P1-2: LN 581_SRT-S | OP | AC | 132.52 % | 3220.44 | B | 4267.66 | 44.06 | |
| GD1 | DVP | 8SPOTSYL-8MORRSVL 500.0 kV Ckt 1 line | Base Case | OP | AC | 104.94 % | 3220.44 | A | 3379.54 | 30.45 | |
| GD1 | DVP | AE1-157 TP-6LDYSMITH CT 230.0 kV Ckt 1 line | DVP_P1-2: LN 574_SRT-S | OP | AC | 106.91 % | 1123.3 | B | 1200.87 | 24.66 |
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 AF1-128 was evaluated as a 411.5 MW injection in the Dominion 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.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD1 | DVP | 6BREMO-6BREMODIST 230.0 kV Ckt 1 line | DVP_P1-2: LN 534_SRT-L | OP | AC | 108.48 % | 678.68 | B | 736.22 | 20.97 | |
| GD1 | DVP | 6BREMODIST-6FORK UNION 230.0 kV Ckt 1 line | DVP_P1-2: LN 534_SRT-L | OP | AC | 108.04 % | 678.68 | B | 733.22 | 20.97 |
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 | DVP | 6CUNNING-6MTEAGLE 230.0 kV Ckt 1 line | DVP_P1-2: LN 534_SRT-L | OP | AC | 103.72 % | 661.76 | B | 686.41 | 21.92 | |
| GD1 | DVP | 6FORK UNION-6CUNNING 230.0 kV Ckt 1 line | DVP_P1-2: LN 534_SRT-L | OP | AC | 105.01 % | 661.76 | B | 694.91 | 21.92 | |
| GD1 | DVP | 6MTEAGLE-6CHARLVL 230.0 kV Ckt 1 line | DVP_P1-2: LN 534_SRT-L | OP | AC | 102.08 % | 661.76 | B | 675.51 | 21.92 |
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 Requests (projects) in PJM Transition Cycle 1 Cluster 48 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 48 project.
Table 1: Transition Cycle 1 Cluster 48 Projects
Cluster | Project | Fuel Type | Transmission Owner | MFO (MW) | MWE (MW) | MWC (MW) | Point of Interconnection |
48 | AF1-128 | Natural Gas | Dominion | 569 | 569 | 569 | Chesterfield 230 kV |
This analysis is effectively a screening study to determine whether the addition of the Cluster 48 project will meet the dynamics requirements of the NERC, Dominion Energy, and PJM reliability standards.
The load flow scenario for the analysis was based on the Regional Transmission Expansion Plan (RTEP) 2027 light load case, modified to include applicable projects. Projects in vicinity of Cluster 48 have been dispatched online at maximum power output with electrically close generators dispatched near 50% of the respective units minimum reactive power output.
Cluster 48 were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. 126 contingencies were studied, each with a 20 second simulation time period. The studied contingencies included:
- Steady-state operation (30 seconds)
- Three-phase faults with normal clearing time
- Single-phase bus faults with normal clearing time
- Single-phase faults with stuck breaker
- Single-phase faults with delayed clearing at remote end
- Three-phase faults with loss of multiple-circuit tower line.
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 RTEP 2027 light load case:
- Cluster 48 was able to ride through the faults (except for faults where protective action trips a generator(s)),
- The system with Cluster 48 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 in Dominion area.
- 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)
- For Dominion area, the final voltages are within the steady-state voltage ranges below per Dominion Energy’s transmission planning criteria.
- P1 Category Contingencies:
- 0.93 to 1.05 p.u. for 230, 115, 69 kV facilities
- 0.93 to 1.03 p.u. for 138 kV facilities due to legacy switches
- 1.01 to 1.096 p.u. for 500 kV facilities
- P2, P4, P5, and P7 Category Contingencies:
- 0.90 to 1.05 p.u. for 230, 115, 69 kV facilities
- 0.90 to 1.03 p.u. for 138 kV facilities due to legacy switches
- 1.00 to 1.096 p.u. for 500 kV facilities
- No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.
The transmission system being studied met the evaluation criteria. Below are some notable results.
AD2-074 was observed to trip on overvoltage (1.11 p.u. for 1 second and 1.2 p.u. for 0.001 second) for a number of P1 contingencies. Terminal voltage plots showed that the controller for this unit was freezing and not absorbing reactive power within the studied 20 second simulation. After reviewing the dynamic model, it was found that the REGCA model for this unit had reactive power ramp rate parameters Iqrmax and Iqrmin set to 0.02 and -0.02 p.u. respectively. These values are typically set much higher to allow the unit to respond to voltage variations quicker. Therefore, these values were increased to 100 and -100 p.u.. AD2-074 was then able to reduce the voltage post fault which prevented the unit from tripping on the 1.1 p.u. setpoint. The unit was still tripping for the 1.2 p.u. setpoint because of the low time delay (0.001 second). This time delay was increased slightly to 0.0167s. These changes enabled the unit to ride through all faults.
Surry units reactive response took over 20 seconds to settle for some contingencies. A longer 40 second test simulation was conducted which demonstrated that the unit settled shortly after 20 seconds shown in Figure 1 below. Slow settling is not a criteria violation and will not affect the results of the study.
AD1-151 reactive power was found to have some oscillations post fault that are positively damped with adequate damping ratio. This is not a criteria violation.
AB2-134 unit reactive power was found to not settle during the 20 second simulation. The following adjustments were made:
- REPCA CON (J+1) Kp was adjusted to 1
- REPCA CON (J+2) Ki was adjusted to 5
After these adjustments, the reactive power settlement improved but it did not settle within 20 seconds for some contingencies. This is not criteria violation. The developer should be requested to tune the dynamic model.
AB2-190 units reactive power was found to not settle during the 20 second simulation. The following adjustments were made:
- PLNTBU1 CON (J+1) Kp was adjusted to 1
- PLNTBU1 CON (J+2) Ki was adjusted to 5
- PLNTBU1 CON (J+8) Kc was adjusted to 0.04
After these adjustments, the reactive power settlement improved but it did not settle within 20 seconds for some contingencies. This is not criteria violation. The developer should be requested to tune the dynamic model.
AG1-154 reactive power was observed to not settle during the 20 second simulation. The following adjustments were made:
- REPCA CON (J+8) Kc was adjusted to 0.04
This adjustment improved the reactive power settlement for all contingencies.
No mitigation was required.
Reactive Power Analysis
The AF1-128 facility met the 0.95 leading and 0.9 lagging power factor requirements at the generators terminals.
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 |
| AA1-063A | Carolina–Seaboard 115kV | In Service |
| AA1-065 | Earleys 230kV | In Service |
| AA1-139 | Hickory-Shawboro 230kV | In Service |
| AA1-145 | Four Rivers 230kV | In Service |
| AA2-088 | Boykins-Handsome 115kV | In Service |
| AA2-178 | Mackeys 230kV | In Service |
| AB1-027 | Old Church 34.5 KV | In Service |
| AB1-132 | Thelma 230kV | In Service |
| AB1-173 | Brink-Trego 115kV | In Service |
| AB2-022 | Elizabeth City 34.5kV | In Service |
| AB2-024 | Correctional 34.5kV | In Service |
| AB2-025 | Sapony 34.5kV | In Service |
| AB2-026 | Powhatan 34.5kV | In Service |
| AB2-040 | Brink 115kV | In Service |
| AB2-099 | Ahoskie 34.5kV | In Service |
| AB2-100 | Clubhouse-Lakeview 230kV | In Service |
| AB2-134 | Hopewell-Surry 230kV | In Service |
| AB2-161 | Waverly #2 DP 115kV | In Service |
| AB2-174 | Emporia-Trego 115kV | In Service |
| AB2-190 | Hopewell-Surry 230kV | In Service |
| AC1-027 | Pendleton 34.5kV | In Service |
| AC1-034 | Heartsease DP - Mayo Dunbar 115kV | Engineering & Procurement |
| AC1-065 | Harmony Village-Shackleford 115kV | Suspended |
| AC1-086 | Thelma 230kV | Under Construction |
| AC1-112 | Old Church 34.5kV | In Service |
| AC1-118 | Westmoreland 34.5kV | In Service |
| AC1-147 | Grassfield 34.5kV | In Service |
| AC1-161 | Septa 500kV | In Service |
| AC1-164 | Chickahominy 230kV | Partially in Service - Under Construction |
| AC1-189 | Chinquapin-Everetts 230kV | Under Construction |
| AC1-191 | Elmont 115kV | Engineering & Procurement |
| AC1-208 | Cox-Whitakers 115kV | Under Construction |
| AC1-216 | Hopewell-Surry 230kV | In Service |
| AC2-012 | Grassfield-Great Bridge 115kV | In Service |
| AC2-079 | Ivor-Oak Ridge 115kV | Under Construction |
| AC2-137 | Elko 34.5kV | In Service |
| AC2-138 | Northern Neck 34.5kV | In Service |
| AC2-141 | Septa 500kV | Engineering & Procurement |
| AC2-165 | Bremo-Powhatan 230kV | Suspended |
| AD1-022 | Cashie-Trowbridge 230 kV | Engineering & Procurement |
| AD1-025 | Hopewell-Surry 230 kV | In Service |
| AD1-033 | Fentress-Landstown 230 kV | In Service |
| AD1-041 | Harmony Village-Shackleford 115 kV | In Service |
| AD1-056 | Hornertown-Hathaway 230 kV | Suspended |
| AD1-057 | Hornertown-Hathaway 230 kV | Suspended |
| AD1-063 | Harmony Village 34.5 kV | In Service |
| AD1-074 | Trowbridge 230 kV | Engineering & Procurement |
| AD1-075 | Trowbridge 230 kV | Engineering & Procurement |
| AD1-076 | Trowbridge 230 kV | Engineering & Procurement |
| AD1-082 | Bakers Pond-Ivor 115kV | In Service |
| AD1-087 | Clover-Sedge Hill 230 kV | In Service |
| AD1-088 | Briery-Clover 230 kV | Suspended |
| AD1-105 | Kings Dominion DP 115 kV | Under Construction |
| AD1-144 | Kings Fork 34.5 kV | In Service |
| AD1-151 | Hopewell-Surry 230 kV | Suspended |
| AD2-030 | Wan 34.5 kV | In Service |
| AD2-033 | Chase City-Lunenburg 115 kV | Under Construction |
| AD2-073 | Sanders DP 230 kV | In Service |
| AD2-074 | Garner DP-Lancaster 115 kV | Under Construction |
| AD2-085 | Myrtle-Windsor DP 115kV | Engineering & Procurement |
| AD2-202 | Clover-Sedge Hill 230kV | In Service |
| AE1-072 | Shawboro-Sligo 230 kV | Under Construction |
| AE1-074 | Winterpock 34.5 kV | Under Construction |
| AE1-075 | Powhatan 34.5 kV | In Service |
| AE1-103 | Holland-Union Camp 115 kV | Suspended |
| AE1-149 | Disputanta-Poe 115 kV | Suspended |
| AE1-155 | Garner-Northern Neck 115 kV | In Service |
| AE1-157 | Ladysmith CT-St. Johns 230 kV | Under Construction |
| AE1-162 | Smithfield 34.5 kV | In Service |
| AE1-173 | Carson-Suffolk 500 kV | Under Construction |
| AE1-175 | Light Foot 34.5 kV | In Service |
| AE1-190 | Harmony Village-Shackleford 115 kV | In Service |
| AE1-191 | Harmony Village-Shackleford 115 kV | In Service |
| AE2-027 | Harrowgate-Locks 115kV | Suspended |
| AE2-033 | Clubhouse-Sapony 230 kV | Suspended |
| AE2-034 | Mackeys 230 kV | Partially in Service - Under Construction |
| AE2-040 | Sapony 34.5 kV | In Service |
| AE2-041 | Harmony Village 230 kV | Engineering & Procurement |
| AE2-051 | Carson-Septa 500 kV | Engineering & Procurement |
| AE2-094 | Carson-Rogers Road 500 kV | Engineering & Procurement |
| AE2-104 | Suffolk 115 kV | Withdrawn |
| AE2-156 | Yadkin 115 kV | Engineering & Procurement |
| AE2-212 | Harrowgate 34 kV | Engineering & Procurement |
| AE2-247 | Myrtle-Windsor 115 kV | Engineering & Procurement |
| AE2-253 | Hickory-Moyock 230 kV | In Service |
| AE2-259 | Curdsville-Willis Mtn 115 kV | Engineering & Procurement |
| AE2-346 | Ahoskie 34.5 kV | In Service |
| AF1-017 | Myrtle-Windsor 115 kV | Engineering & Procurement |
| AF1-018 | Harmony Village 230 kV | Engineering & Procurement |
| AF1-028 | Endless Caverns 115 kV | Partially in Service - Under Construction |
| AF1-032 | Suffolk 34.5 kV | In Service |
| AF1-042 | Garner DP-Lancaster 115 kV | Engineering & Procurement |
| AF1-069 | Carson-Rogers Rd 500 kV | Engineering & Procurement |
| AF1-114 | Oak Grove-Dahlgren 230 kV | Engineering & Procurement |
| AF1-123 | Harper 230 kV | Under Construction |
| AF1-124 | Harper 230 kV | Partially in Service - Under Construction |
| AF1-125 | Harper 230 kV | Under Construction |
| AF1-129 | Chesterfield 230 kV | Engineering & Procurement |
| AF1-291 | Tyler 34.5 kV | Engineering & Procurement |
| AF1-292 | Fields 34.5kV | Under Construction |
| AF1-294 | Jetersville-Ponton 115 kV | Engineering & Procurement |
| AF2-013 | Arnold's Corner-Dahlgren 230 kV | Engineering & Procurement |
| AF2-042 | Clover-Rawlings 500 kV | Engineering & Procurement |
| AF2-043 | Suffolk 34.5 kV | In Service |
| AF2-054 | Wan 34.5 kV | In Service |
| AF2-077 | White Marsh 34.5 kV | In Service |
| AF2-081 | Moyock 230 kV | Engineering & Procurement |
| AF2-085 | Midlothian 34.5 kV | In Service |
| AF2-091 | Oak Grove-Dahlgren 230 kV | Engineering & Procurement |
| AF2-110 | Suffolk 115 kV | Withdrawn |
| AF2-115 | Jetersville-Ponton 115 kV | Engineering & Procurement |
| AF2-120 | Garner-Northern Neck 115 kV | Under Construction |
| AF2-144 | Powhatan 34.5 kV | In Service |
| AF2-222 | Madisonville DP-Twitty's Creek 115 kV | Engineering & Procurement |
| AF2-299 | Fields 34.5 kV | Engineering & Procurement |
| AG1-007 | Tar River 12.5 kV | Engineering & Procurement |
| AG1-021 | Jetersville-Ponton 115 kV | Engineering & Procurement |
| AG1-037 | Ahoskie 34.5 kV | Withdrawn |
| AG1-038 | Garner DP-Lancaster 115 kV | Engineering & Procurement |
| AG1-105 | Mount Laurel-Barnes Junction 115 kV | Under Construction |
| AG1-135 | Garner-Lancaster 115 kV | Under Construction |
| AG1-145 | Lightfoot 34.5 kV | In Service |
| AG1-153 | Heritage 500 kV | Under Construction |
| AG1-210 | Northern Neck 34.5 kV | Withdrawn |
| AG1-282 | Dunnsville 34.5 kV | Withdrawn |
| AG1-285 | Chase City-Central 115 kV | Engineering & Procurement |
| AG1-342 | Dryburg 115 kV | Engineering & Procurement |
| AG1-532 | Fields 34.5 kV | Under Construction |
| AG1-536 | Garner-Northern Neck 115 kV | Engineering & Procurement |
| AG1-558 | Buckner 34.5 kV | Withdrawn |
| AG1-559 | Caroline Pines 22 kV | Withdrawn |
| V4-068 | Murphy's 34.5kV | In Service |
| W1-029 | Winfall 230kV | In Service |
| Y1-086 | Morgans Corner | In Service |
| Z1-036 | WinFall-Chowan 230kV | In Service |
| Z1-068 | Birdneck 34.5kV | In Service |
| Z2-027 | Pasquotank 34.5kV | 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:
| TO | RTEP ID | Title | Category | Allocated Cost ($USD) | Facilities Study |
|---|---|---|---|---|---|
| Dominion | b3692 | Rebuild approximately 27.7-miles of 500 kV transmission line from Elmont to Chickahominy. | Contingent | $0 | N/A |
| Grand Total: | $0 | ||||
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: b3692
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b3692
- Title
- Rebuild approximately 27.7-miles of 500 kV transmission line from Elmont to Chickahominy.
- Description
- Rebuild approximately 27.7-miles of 500 kV transmission line from Elmont to Chickahominy with current 500 kV standards construction practices to achieve a summer rating of 4330 MVA. Projected ISD: 06/01/2026
- Cost Information
- Time Estimate
- Jun 01 2026
Contingent Note: Although AF1-128 may not presently have cost responsibility for this upgrade, AF1-128 may need this upgrade in-service to be deliverable to the PJM system. If AF1-128 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 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 8CHCKAHM-8ELMONT 500.0 kV Ckt 1 line | (Any) |
|
Attachments
AF1-128 One Line Diagram
