AH1-713 Phase II System Impact Study Report
v1.00 released 2026-06-03 17:57
Mt. Storm 500kV
14.0 MW Capacity / 0.0 MW Energy
Introduction
This Phase II System Impact Study (SIS) Report has been prepared in accordance with the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 310 for New Service Requests (projects) in Transition Cycle 2 (TC2). 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 Phase II 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 Phase II 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 4.5, PJM takes the following actions during the Phase II System Impact Study:
- PJM will retool load flow results from the Phase I System Impact Study (summer peak, winter peak and light load) based on decisions made by Project Developers or Eligible Customers during Decision Point I.
- PJM will conduct any required voltage analyses.
- PJM will perform short circuit and stability analyses as required.
- PJM will coordinate with the Affected System to confirm which projects in the PJM Cycle will require Affected System studies. If the Affected System Operator indicates that an Affected System study is required, PJM will:
- Notify the Project Developer or Eligible Customer of the need for an Affected System study and the requirement to execute an Affected System study agreement with the impacted Affected System Operator, and;
- Include the results of the Affected System Operator’s Affected System Study in the Phase II System Impact Study results, if applicable and available.
- The Phase II System Impact Study Results will be publicly available on PJM’s website. Project Developers and Eligible Customers must obtain the results from the website.
The Transmission Owner takes the following actions during the Phase II System Impact Study:
- Verify Interconnection Facilities and Network Upgrades required to accommodate the New Service Request.
- Perform a Facilities Study. The Facilities Study in Phase II System Impact Study phase will be for the physical Interconnection Facilities. The Facilities Study requirements are outlined in Attachment C of this manual. The study will be conducted pursuant to Tariff, Part VII, Subpart D, section 307(A)(7) and Tariff, Part VIII, Subpart C, section 404(A)(7).
Decision Point II Requirements
At the close of Phase II System Impact Study, PJM will initiate Decision Point II (DP2). During DP2, the Project Developer will have 30 days to decide whether to proceed with their project. If the Project Developer elects to proceed, they should provide the elements defined in the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 311.A. Additional information on these elements is available in PJM Manual 14H sections 4.6, 6, and 7.
Allowable project modifications at Decision Point II are defined in PJM Open Access Transmission Tariff, Part VII, Subpart D, section 311.B. Additional information regarding allowable project modifications can be found in PJM Manual 14H, section 9.8.
Adverse Test Eligibility
This New Service Request does not meet the Adverse Study Impact Criteria and has the option to either move forward in the Cycle process or withdraw at DP2 with Readiness Deposit #1 forfeited. See adverse study impact calculation below.
This section details whether a Project Developer or Eligible Customer qualifies for the Adverse Study Impact clause outlined in the PJM OATT, Part VII, Subpart D, section 311.B and Manual 14H, section 6.2.2. In order to qualify for an Adverse Study Impact at Decision Point II, the Network Upgrade cost from Phase I to Phase II must:
- Increase overall by 25% or more
- Increases by more than $10,000 per MW (Includes Costs identified in Affected System studies)
If a New Service Request meets the criteria above and chooses to withdraw the request, PJM will refund the cumulative Readiness Deposit amounts paid at the Application Phase and at Decision Point I (RD1 and RD2, respectively).
The below calculations show the computation of this New Service Request's Adverse Study Impact
General
The Project Developer has proposed a Coal generating facility located in the Virginia Electric and Power Company (d/b/a Dominion Energy Virginia) zone — Grant County, West Virginia. The installed facilities will have a total capability of 538.0 MW with 14.0 MW of this output being recognized by PJM as Capacity.Project Information
Physical Interconnection Facility Study
A Physical Interconnection Facilities Study is not required for this project.
Point of Interconnection
AH1-713 will interconnect on the Virginia Electric and Power Company (d/b/a Dominion Energy Virginia) transmission system as an uprate to S74/S76 at the Mt. Storm 500 kV Substation.
Cost Summary
The table below shows a summary of the total cost estimates for this New Service Request project. In Phase II SIS, the interconnected Transmission Owner has performed a facilities study for both the Transmission Owner Interconnection Facilities (TOIF) and Physical Interconnection Network Upgrades. The System Reliability Network Upgrade shown in the table are planning level cost estimates which are subject to change as a result of a facility study performed by the TO during Phase III System Impact Study.
Based on the Phase II SIS results, the AH1-713 project has the following allocation of costs for interconnection. The cost contribution towards Readiness Deposit #3 are also shown below.
| Cost Summary | |||
|---|---|---|---|
| Description | Cost Allocated to AH1-713 | Cost Subject to Readiness* | Cost Subject to Adverse |
| Transmission Owner Interconnection Facilities (TOIF) | $0 | $0 | $0 |
| Other Scope | $0 | $0 | $0 |
| Option To Build Oversight | $0 | $0 | $0 |
| Physical Interconnection Network Upgrades | |||
| Stand Alone Network Upgrades | $0 | $0 | $0 |
| Network Upgrades | $0 | $0 | $0 |
| System Reliability Network Upgrades | |||
| Steady State Thermal & Voltage | $0 | $0 | $0 |
| Transient Stability | $0 | $0 | $0 |
| Short Circuit | $0 | $0 | $0 |
| Transmission Owner Analysis | |||
| SubRegional | $0 | $0 | $0 |
| Distribution | $0 | $0 | $0 |
| Affected System Reinforcements | |||
| AFS - PJM Violations | $0 | $0 | $0 |
| AFS - Non-PJM Violations | $0 | $0 | $0 |
| Total | $0 | $0 | $0 |
* Contributes to calculation for Readiness Deposit #3 (RD3). See Readiness Deposit section of report for additional detail.
Definitions
Transmission Owner Interconnection Facilities: Facilities that are owned, controlled, operated and maintained by the Transmission Owner on the Transmission Owner’s side of the Point of Change of Ownership to the Point of Interconnection, including any modifications, additions or upgrades made to such facilities and equipment, that are necessary to physically and electrically interconnect the Generating Facility with the Transmission System or interconnected distribution facilities.
Stand Alone Network Upgrades: Network Upgrades, which are not part of an Affected System, which a Project Developer may construct without affecting day-to-day operations (e.g. taking a transmission outage) of the Transmission System during their construction.
Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider’s overall Transmission System for the general benefit of all users of such Transmission System. Network Upgrades have no impact or potential impact on the Transmission System until the final tie-in is complete.
Notes
Note 1: PJM Open Access Transmission Tariff (OATT), Part VII, Subpart D, section 307.5 outlines cost allocation rules. The rules are further clarified in PJM Manual 14H, section 4.2.6. PJM shall identify the New Service Requests in the Cycle contributing to the need for the required Network Upgrades within the Cycle. All New Service Requests that contribute to the need for a Network Upgrade will receive cost allocation for that upgrade pursuant to each New Service Request’s contribution to the reliability violation identified on the transmission system in accordance with PJM Manuals.
Note 2: There will be no inter-Cycle cost allocation for Interconnection Facilities or Network Upgrades identified in the System Impact Study costs identified in a Cycle; all such costs shall be allocated to New Service Requests in that Cycle.
Note 3: For Project Developers with System Reinforcements listed: If this project presents cost allocation to a System Reinforcement indicates $0, then please be aware that as changes to the interconnection process occur, such as other projects withdrawing, reducing in size, etc, the cost responsibilities can change and a cost allocation may be assigned to this project. In addition, although this project presents cost allocation to a System Reinforcement is presently $0, this project may need this system reinforcement completed to be deliverable to the PJM system. If this project desires to come into service prior to completion of the system reinforcement, the Project Developer will need to request PJM to perform an interim 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.
Note 4: Please see the ‘Affected Systems Studies’ section of this Phase II SIS report for details on your project’s need for an Affected Systems Study. If your project requires an Affected Systems Study, the Affected Systems impacts may not be available from the Affected System Operator at the time of the PJM Phase II SIS. Therefore, the cost in this section would not reflect any required upgrades by the Affected System until the study is completed. If your project requires an Affected Systems Study and your results are not provided for Phase II SIS, PJM anticipates providing them in the Phase III SIS per Tariff Part VII.D.312.
Readiness Deposit
Per Tariff Part VII, Subpart D, section 311 (Decision Point II) A.1.b and PJM Manual 14H, section 6.2, Readiness Deposit #3 (RD3) are funds committed by the Project Developer or Eligible Customer based upon the applicable contribution to Network Upgrades as defined below. Readiness Deposits are not used to fund studies nor to offset Security.
During Decision Point II (DP2), the Project Developer or Eligible Customer is required to submit Readiness Deposit #3, which is calculated as 20% of cost allocation for required Phase II Network Upgrades minus Readiness Deposit #1 & Readiness Deposit #2.
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.
Note 2: Readiness Deposit #1 (RD1) = ($4,000 * Project Size (MW))
Note 3: Readiness Deposit #2 (RD2) = 10% of cost allocation for required Network Upgrades minus RD1. Readiness Deposit #2 (RD2) can be zero, but may not be a negative number.
Note 4: Readiness Deposit #3 can be zero, but may not be a negative number.
Readiness Deposit #3 Due for Project AH1-713
Readiness Deposit #3 has been calculated for the project based on the Phase II System Impact Study results and is shown in the table below. This Readiness Deposit #3 must be provided at Decision Point II through either a wire transfer or letter of credit per Manual 14H, Section 6.2.
Readiness Deposit #3 Due for AH1-713
For additional detail regarding Readiness Deposit Refunds, reference PJM Manual 14H, section 6.2.1. The Readiness Deposit Letter of Credit template can be found here.
Transmission Owner Scope of Work
AH1-713 is sharing a POI and the TOIF with , so there are no associated interconnection costs for this project. Should the previous project(s) S74/S76 withdraw from the Interconnection Queue, AH1-713 will assume responsibility of the Transmission Owner Interconnection Facilities and Network Upgrades costs identified in the S74/S76 study report(s) for interconnection to the Dominion System.
No TO Interconnection Facilities or Physical Network Upgrades are required for this project.
Transmission Owner Analysis
PJM performed a power flow analysis of the transmission system using a 2028 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 AH1-713 was evaluated as a 0.0 MW (14.0 MW Capacity) injection in the Dominion area.
AH1-713 was evaluated as part of a plant. The total Energy output of the plant was evaluated at its maximum seasonal capability of 538.0 MW (0.0 MW under study).
Note: The capacity portion of Generation Interconnection Requests are evaluated for single or N-1 contingencies. The energy portion, ramped up to a percentage of its full energy output based on season and fuel-specific ramping limits, of Generation Interconnection Requests are evaluated for multiple facility (common mode) contingencies (double circuit tower line, fault with a stuck breaker, and bus fault). For additional details regarding Generator Deliverability, reference PJM Manual 14B, Attachment C, Section C.3.
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 | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD2 | DVP/PEPCO | 6EDFERRY-DICKH230 230.0 kV Ckt 1 line | AP_P2-3_PE-500-019B_SRT-A | Breaker | AC | 121.4 % | 1417.0 | B | 1720.2 | 0.7 | |
| GD2 | DVP | 8FRONT ROYAL-8MORRSVL 500.0 kV Ckt 1 line | AP_P1-2_PE-500-404T_SRT-A | Single | AC | 100.67 % | 3220.44 | B | 3241.91 | 2.05 |
Winter Peak Analysis
The New Service Request AH1-713 was evaluated as a 0.0 MW (14.0 MW Capacity) injection in the Dominion area.
AH1-713 was evaluated as part of a plant. The total Energy output of the plant was evaluated at its maximum seasonal capability of 538.0 MW (0.0 MW under study).
Note: The energy portion, ramped up to a percentage of its full energy output based on season and fuel-specific ramping limits, of Generation Interconnection Requests are evaluated for single or N-1 contingencies and multiple facility (common mode) contingencies (double circuit tower line, fault with a stuck breaker, and bus fault). For additional details regarding Generator Deliverability, reference PJM Manual 14B, Attachment C, Section C.3.
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 Analysis
The New Service Request AH1-713 was evaluated as a 0.0 MW injection
AH1-713 was evaluated as part of a plant. The total Energy output of the plant was evaluated at its maximum seasonal capability of 538.0 MW (0.0 MW under study).
Note: The capacity portion of Generation Interconnection Requests are evaluated for single or N-1 contingencies. The energy portion, ramped up to a percentage of its full energy output based on season and fuel-specific ramping limits, of Generation Interconnection Requests are evaluated for multiple facility (common mode) contingencies (double circuit tower line, fault with a stuck breaker, and bus fault). For additional details regarding Generator Deliverability, reference PJM Manual 14B, Attachment C, Section C.3.
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
Analysis Complete - No Issues
Based on PJM’s TC2 Phase II Short Circuit Analysis, this project did not contribute >1% fault duty to any previously identified overdutied breakers, nor did it cause any new overdutied breakers.
Please note that in TC2 Phase III, PJM will perform additional analysis including the evaluation of impacts from topology upgrades which may have potential effects on breaker duties not seen in the Phase II analysis.
Stability Analysis
PJM has reviewed this project submission and determined that a stability study is not required as this is a CIR only increase with no changes to equipment/electrical parameters (no change to MFO).
Reactive Power Analysis
Not Required
Reactive Power Analysis was not performed. This project is responsible for meeting all applicable power factor requirements based on the project Agreements per PJM’s Tariff, Part IX, Subpart B, App. 2, section 4.6.1.
Steady-State Voltage Analysis
Not Required
A steady state voltage analysis is evaluated on a project-by-project basis and depends on specific project parameters. For this project, a steady state voltage analysis is not required per PJM's Manual 14H, Section 4.5.2.
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.
(No dependencies were identified)
Affected System - PJM Identified Violations
As part of PJM's analysis, per Tariff Part VII.G.336 & Manual 14H, Section 13, 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 accordance with PJM Tariff Part VII, Subpart D, section 310.A and as outlined in PJM Manual 14H, Sections 4.5 and 13, in Phase II of the Cycle, PJM provides the Affected System Operator any updates on the PJM projects that require an Affected Systems Study based on their response at DP1. New Service Requests that require an Affected Systems Study are required to enter into an Affected Systems Study Agreement with the Affected System Operator, as applicable, prior to the close of DP2 or they will be withdrawn from the Cycle.
If the Project Developer already entered into the necessary agreement and the results are available, PJM will supply them in the Phase II SIS report. See below for the status of any required Affected Systems Study. A status of “Pending” means that the study is not yet completed by the Affected System Operator. If your project requires an Affected Systems Study and your results are not provided for Phase II SIS, PJM anticipates providing them in the Phase III SIS per Tariff Part VII.D.312.
System Reinforcements
No cost allocated system reinforcements were identified for this project in the Phase II System Impact Study load flow analysis.
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: b4000.357
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.357
- Title
- Build a new 765/500/230 kV substation called Yeat. Install (2) 765/500 kV transformers. Cut in 500 kV line Bristers-Ox and 500 kV line Meadowbrook-Vint Hill into Yeat.
- Description
- Build a new 765/500/230 kV substation called Yeat. Install (2) 765/500 kV transformers. Cut in 500 kV line Bristers-Ox and 500 kV line Meadowbrook-Vint Hill into Yeat.
- Cost Information
- Time Estimate
- Jun 01 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.356
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.356
- Title
- Build a new 156 mile 765kV line from Joshua Falls – Yeat. (Roughly 86.7 miles in Dominion section).
- Description
- Build a new 156 mile 765kV line from Joshua Falls – Yeat. (Roughly 86.7 miles in Dominion section).
- Cost Information
- Time Estimate
- Jun 01 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.355
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b4000.355
- Title
- Build a new 156 mile 765kV line from Joshua Falls – Yeat. (Roughly 69.3 miles in AEP section).
- Description
- Build a new 156 mile 765kV line from Joshua Falls – Yeat. (Roughly 69.3 miles in AEP section).
- Cost Information
- Time Estimate
- Jun 01 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.352
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.352
- Title
- Cut in Line #568 Ladysmith - Possum Point into Thornburg (formerly Kraken), creating new Line #568 Thornburg (formerly Kraken) to Possum Point.
- Description
- Cut in Line #568 Ladysmith - Possum Point into Thornburg (formerly Kraken), creating new Line #568 Thornburg (formerly Kraken) to Possum Point.
- Cost Information
- Time Estimate
- Sep 16 2030
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.351
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.351
- Title
- Cut in Line #568 Ladysmith - Possum Point into Thornburg (formerly Kraken), creating Line #9517 Ladysmith to Thornburg (formerly Kraken).
- Description
- Cut in Line #568 Ladysmith - Possum Point into Thornburg (formerly Kraken), creating Line #9517 Ladysmith to Thornburg (formerly Kraken).
- Cost Information
- Time Estimate
- Sep 16 2030
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.349
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.349
- Title
- Update relay settings at Ladysmith to change the destination of 500kV line #568 from Possum Point to Thornburg (formerly Kraken).
- Description
- Update relay settings at Ladysmith to change the destination of 500kV line #568 from Possum Point to Thornburg (formerly Kraken).
- Cost Information
- Time Estimate
- Sep 16 2030
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.348
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.348
- Title
- Build a new 500/230kV substation called Thornburg (formerly Kraken). The 500kV, 5000A ring bus will be set up for a redundant breaker configuration. Install (2) 1400MVA 500/230 kV transformers.
- Description
- Build a new 500/230kV substation called Thornburg (formerly Kraken). The 500kV, 5000A ring bus will be set up for a redundant breaker configuration. Install (2) 1400MVA 500/230 kV transformers. A new redundant breaker ring will be added at Thornburg (formerly Kraken) to accommodate the new 500kV line from North Anna to Thornburg (formerly Kraken).
- Cost Information
- Time Estimate
- Jun 01 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.346
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.346
- Title
- Cut-in 500kV line from Thornburg (formerly Kraken) substation into Yeat substation
- Description
- Cut-in 500kV line from Thornburg (formerly Kraken) substation into Yeat substation
- Cost Information
- Time Estimate
- Jun 01 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.344
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.344
- Title
- Build a 500kV line from North Anna substation (bypassing Ladysmith Substation) to a new substation called Thornburg (formerly Kraken). New conductor to have a minimum summer normal rating of 4357MVA.
- Description
- Build a 500kV line from North Anna substation (bypassing Ladysmith Substation) to a new substation called Thornburg (formerly Kraken). New conductor to have a minimum summer normal rating of 4357MVA.
- Cost Information
- Time Estimate
- Sep 16 2030
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.341
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.341
- Title
- Remove the 500 kV conductor previously planned to terminate into the Vint Hill 500 kV Substation and extend approximately 0.2 miles of conductor to fly-over the site.
- Description
- Remove the 500 kV conductor previously planned to terminate into the Vint Hill 500 kV substation and extend approximately 0.2 miles of conductor to fly-over the site.
- Cost Information
- Time Estimate
- Jul 13 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.342
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.342
- Title
- Remove the terminal equipment and substation work required for the termination of the Morrisville-Wishing Star 500 kV line into Vint Hill.
- Description
- Remove the terminal equipment and substation work required for the termination of the Morrisville-Wishing Star 500 kV line into Vint Hill.
- Cost Information
- Time Estimate
- Jul 13 2029
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.345
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.345
- Title
- Build a 500kV line from a new substation called Thornburg (formerly Kraken) to a new substation called Yeat. New conductor to have a minimum summer normal rating of 4357MVA.
- Description
- Build a 500kV line from a new substation called Thornburg (formerly Kraken) to a new substation called Yeat. New conductor to have a minimum summer normal rating of 4357MVA.
- Cost Information
- Time Estimate
- Sep 16 2030
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4000.350
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4000.350
- Title
- Update relay settings at Possum Point to change the destination of 500kV line #568 from Ladysmith to Thornburg (formerly Kraken).
- Description
- Update relay settings at Possum Point to change the destination of 500kV line #568 from Ladysmith to Thornburg (formerly Kraken).
- Cost Information
- Time Estimate
- Sep 16 2030
Not ContingentTopology Changing Note 1: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade. Note 2: This topology changing reinforcement was developed by the transmission owner and modeled in PJM analysis to address cycle overload(s). A flowgate that this project contributed to was identified as requiring this topology reinforcement.
| Facility | Contingency | ||
|---|---|---|---|
| 8MORRSVL-8FRONT ROYAL 500.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.11
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.11
- Title
- Replace Bells Mill T3 XF with new PEPCO standard 260 MVA 230/138 kV transformer.
- Description
- Replace Bells Mill T3 XF with new PEPCO standard 260 MVA 230/138 kV transformer. (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.10
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.10
- Title
- Replace one stranded bus conductor, three thermal relays, two disconnect switches at Quince Orchard 230 kV substation.
- Description
- Replace one stranded bus conductor, three thermal relays, two disconnect switches at Quince Orchard 230 kV substation. (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.9
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.9
- Title
- Replace two breakers, one bushing CT, one stranded bus conductor, four disconnect switches at Brighton 500 kV substation.
- Description
- Replace two breakers, one bushing CT, one stranded bus conductor, four disconnect switches at Brighton 500 kV substation.
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.8
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.8
- Title
- Relocate Dickerson "D"-Quince Orchard 23035 to terminate at Dickerson "H" at Dickerson No. 2 tie location.
- Description
- Relocate Dickerson "D"-Quince Orchard 23035 to terminate at Dickerson "H" at Dickerson No. 2 tie location. (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.7
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.7
- Title
- Install 3.2% 230 kV series reactor at Dickerson "H" terminal side of the Edwards Ferry-Dickerson circuit.
- Description
- Install 3.2% 230 kV series reactor at Dickerson "H" terminal side of the Edwards Ferry-Dickerson circuit. (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.6
- Type
- Load Flow
- TO
- Dominion
- RTEP ID / TO ID
- b4052.6
- Title
- Aspen 500 kV remote work for Dickerson (new 500 kV) - Aspen line
- Description
- Aspen 500 kV remote work for Dickerson (new 500 kV) - Aspen line (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.5
- Type
- Load Flow
- TO
- APS
- RTEP ID / TO ID
- b4052.5
- Title
- Rocky Point 500 kV remote work for Dickerson (new 500 kV)-Rocky Point line
- Description
- Rocky Point 500 kV remote work for Dickerson (new 500 kV)-Rocky Point line. (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.1
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.1
- Title
- New 500/230 kV substation (Dickerson) by cutting into the Aspen-Rocky Point 500 kV line
- Description
- New 500/230 kV substation (Dickerson) by cutting into the Aspen-Rocky Point 500 kV line. (2025-W1-919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.4
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.4
- Title
- Aspen-Dickerson (new 500 kV) termination work at Dickerson 500 kV
- Description
- Aspen-Dickerson (new 500 kV) termination work at Dickerson 500 kV (2025 W1 919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.3
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.3
- Title
- Rocky Point-Dickerson (new 500 kV) termination work at Dickerson 500 kV
- Description
- Rocky Point-Dickerson (new 500 kV) termination work at Dickerson 500 kV (2025 W1-919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b4052.2
- Type
- Load Flow
- TO
- PEPCO
- RTEP ID / TO ID
- b4052.2
- Title
- Install two 500/230 kV transformers connecting a new 500 kV Dickerson station and DIckeson "H" 230 kV station including 230 kV substation work.
- Description
- Install two 500/230 kV transformers connecting a new 500 kV Dickerson station and DIckeson "H" 230 kV station including 230 kV substation work. (2025 W1-919)
- Cost Information
- Time Estimate
- Jun 01 2032
Not Contingent Note: AH1-713 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AH1-713 is not contingent on this baseline upgrade as it does not meet the criteria for being a contingent facility or for having cost allocation for the upgrade.
| Facility | Contingency | ||
|---|---|---|---|
| DICKH230-6EDFERRY 230.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. |
Attachments
AH1-713 One Line Diagram
