This Phase III System Impact Study Report (PH3) has been prepared in accordance with the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 312 for New Service Requests (projects) in Transition Cycle 1. The Project Developer/Eligible Customer (developer) is Virginia Electric and Power Company, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Virginia Electric and Power Company (Dominion Virginia Power).

New Service Requests meeting the requirements of Tariff, Part VII, Subpart D, Decision Point II, were included in the Phase III System Impact Study. The Phase III System Impact Study is conducted on an aggregate basis within a New Services Request’s Cycle, and results are provided in both (i) a single Cycle executive summary format and (ii) an individual project-level basis. The Phase III System Impact Study Results (for both the executive summary and individual reports) will be publicly available on PJM’s website. Developers must obtain the results from the website.

In accordance with PJM Manual 14H, section 4.7, PJM takes the following actions during the Phase III System Impact Study:

1. PJM will retool load flow, short circuit and stability results based on decisions made by Project Developers or Eligible Customers during Decision Point II.
2. PJM will coordinate with Affected System Operators to conduct any studies required to determine the final impact of a New Service Request on any Affected System and will include the final Affected System Study results in the Phase III System Impact Study, if available from the Affected System.
3. The Phase III System Impact Study Results will be publicly available on PJM’s website; Project Developers and Eligible Customers must obtain the results from the website.
4. PJM will tender draft final agreements to Project Developers or Eligible Customers.

The Transmission Owner takes the following actions during the Phase III System Impact Study:

1. Verify Interconnection Facilities and Network Upgrades required to accommodate the New Service Request.
2. Perform a Facilities Study. The Facilities Study in Phase III System Impact Study phase will be for the System Reliability Network Upgrades. The Facilities Study requirements are outlined in Attachment C of PJM Manual 14H. The study will be conducted pursuant to Tariff, Part VII, Subpart D, section 307(A)(7).

At the close of Phase III System Impact Study, PJM will initiate Decision Point III (DP3). During DP3, the Project Developer will have 30 days to decide whether to proceed with their project. If the Project Developer elects to proceed, they should provide the elements defined in the PJM Open Access Transmission Tariff, Part VII, Subpart D, section 313.A. Additional information on these elements is available in PJM Manual 14H sections 4.8, 6, and 7.

As stated in PJM Tariff, Part VII, Subpart D, section 313.C, New Service Requests may not be changed or modified in any way for any reason during Decision Point III. A New Service Request must be withdrawn and resubmitted in a subsequent Cycle to the extent a Project Developer or Eligible Customer wants to make any changes to such New Service Request at this point in the Cycle process.

This New Service Request does not meet the Adverse Study Impact Criteria and has the option to either move forward in the Cycle process or withdraw at DP3 with cumulative Readiness Deposits forfeited. See adverse study impact calculation below.

This section details whether a Project Developer or Eligible Customer qualifies for the Adverse Study Impact clause outlined in the PJM OATT, Part VII, Subpart D, section 313.B and Manual 14H, section 6.2.2. In order to qualify for an Adverse Study Impact at Decision Point III, the Network Upgrade cost from Phase II to Phase III must:

1. Increase overall by 35% or more
2. Increases by more than $25,000 per MW (Includes Costs identified in Affected System studies)

If a New Service Request meets the criteria above and chooses to withdraw the request, PJM will refund the cumulative Readiness Deposit amounts paid at the Application Phase, Decision Point I, and Decision Point II (RD1, and RD2 and RD3, respectively).

The below calculations show the computation of this New Service Request's Adverse Study Impact

The Project Developer has proposed a Natural Gas generating facility located in the Virginia Electric and Power Company (Dominion Virginia Power) 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.

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.

Physical Interconnection Facility Study

The transmission owner has completed the Physical Interconnection Facilities Study. This report is available for download.

AF1-128 will interconnect on the Dominion transmission system via a direct connection at the existing 230 kV Chesterfield Power Station.

The table below shows a summary of the total cost estimates for this New Service Request project. In Phase III SIS, the interconnected Transmission Owner has performed a facilities study for the required System Reliability Network Upgrades. The Facilities Studies for the Transmission Owner Interconnection Facilities (TOIF) and Physical Interconnection Network Upgrades were performed by the Transmission Owner in Phase II and are available for download on PJM.com (see General Section for document links).

Based on the Phase III SIS results, the AF1-128 project has the following allocation of costs for interconnection. The Security amount required at DP3 is also shown below.

* Contributes to calculation for Security. See Security Section of this report for additional detail.

Definitions

Transmission Owner Interconnection Facilities: Facilities that are owned, controlled, operated and maintained by the Transmission Owner on the Transmission Owner’s side of the Point of Change of Ownership to the Point of Interconnection, including any modifications, additions or upgrades made to such facilities and equipment, that are necessary to physically and electrically interconnect the Generating Facility with the Transmission System or interconnected distribution facilities.

Stand Alone Network Upgrades: Network Upgrades, which are not part of an Affected System, which a Project Developer may construct without affecting day-to-day operations (e.g. taking a transmission outage) of the Transmission System during their construction.

Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider’s overall Transmission System for the general benefit of all users of such Transmission System. Network Upgrades have no impact or potential impact on the Transmission System until the final tie-in is complete.

Notes

Note 1: PJM Open Access Transmission Tariff (OATT), Part VII, Subpart D, section 307.5 outlines cost allocation rules. The rules are further clarified in PJM Manual 14H, section 4.2.6. PJM shall identify the New Service Requests in the Cycle contributing to the need for the required Network Upgrades within the Cycle. All New Service Requests that contribute to the need for a Network Upgrade will receive cost allocation for that upgrade pursuant to each New Service Request’s contribution to the reliability violation identified on the transmission system in accordance with PJM Manuals.

Note 2: There will be no inter-Cycle cost allocation for Interconnection Facilities or Network Upgrades identified in the System Impact Study costs identified in a Cycle; all such costs shall be allocated to New Service Requests in that Cycle.

Note 3: For Project Developers with System Reinforcements listed: If this project presents cost allocation to a System Reinforcement indicates $0, then please be aware that as changes to the interconnection process occur, such as other projects withdrawing, reducing in size, etc, the cost responsibilities can change and a cost allocation may be assigned to this project. In addition, although this project presents cost allocation to a System Reinforcement is presently $0, this project may need this system reinforcement completed to be deliverable to the PJM system. If this project desires to come into service prior to completion of the system reinforcement, the Project Developer will need to request PJM to perform an interim deliverability study to determine if they would be deliverable for all or a portion of their output for each delivery year until the system reinforcement is complete.

Per Tariff Part VII, Subpart D, section 313 (Decision Point III) A.1.a and PJM Manual 14H, section 8.6.1, Project Developers and Eligible Customers are required to provide Security in a form acceptable to PJM at Decision Point III which runs concurrently with the projects' Final Agreement Negotiation Phase. Security may be in the form of cash, letter of credit, or other form of Security acceptable to PJM (see PJM M14H, Section 6.4).

Security is calculated for a New Service Request based on the Network Upgrade costs allocated pursuant to the Phase III System Impact Study results.

Note 1: "Network Upgrades" referred to in the calculation include both (i) the Physical Interconnection Network Upgrades and (ii) the System Reliability Network Upgrades as shown in the Cost Summary table.

Security Due for AF1-128

Security has been calculated for the AF1-128 project(s) based on the Phase III System Impact Study results and is shown in the table below. This Security must be provided at Decision Point III through either a wire transfer or letter of credit or other form of Security deemed acceptable by PJM per Manual 14H, Section 6.4.

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.

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 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.

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.

PJM performed a power flow analysis of the transmission system using a 2027 load flow model and the results were verified by Dominion.

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. Refer to AF1-128 Physical Interconnection Facilities Study for additional requirements found in the General Section of the report.

To the extent that these Applicable Technical Requirements and Standards may conflict with the terms and conditions of the Tariff, the Tariff shall control.

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.

The Project Developer will be required to comply with all interconnected Transmission Owner’s revenue metering requirements located at the following link: PJM - Transmission Owner Engineering & Construction Standards and in the Physical Interconnection Facilities Study.

The Phase III Short circuit analysis was conducted for the following two study scenarios

• Scenario 1 - TC1 Projects Impact;
• Scenario 2 - TC1 Topology-Changing Upgrade Impacts;

The starting TC1 Phase III short circuit case is an updated Phase II case that accounted for the DPII outcomes (project changes & withdrawals) and other pre-TC1 changes. The starting Phase III case was utilized for the Scenario 1 studies to determine the impact of TC1 projects without modeling any topology-changing upgrades required for TC1. To conduct the Scenario 2 studies, the required topology-changing upgrades from the latest Load Flow & Stability studies were incorporated into the Scenario 1 case and utilized for the Scenario 2 studies to determine the impact of the topology-changing upgrades on the short circuit results from Scenario 1

Based on PJM Short Circuit Analysis, this project did not contribute >1% fault duty to previously identified overduty breakers, nor did it cause any new overduty breakers.

Analysis Complete - No Issues

Executive Summary

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

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.

The AF1-128 facility met the 0.95 leading and 0.9 lagging power factor requirements at the generators terminals.

Steady State Voltage Analysis is Not Required.

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.