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 Pigeon Run Solar, LLC, 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 an uprate to a planned/existing Solar facility located in the Virginia Electric and Power Company (Dominion Virginia Power) zone — Campbell County, Virginia. This project is an increase to the developer’s AE2-185 project(s), which will share the same Point of Interconnection. The AF2-404 project is a 0.0 MW uprate (0.0 MW Capacity uprate) to the previous project(s). The total installed facilities will have a capability of 60.0 MW with 36.0 MW of this output being recognized by PJM as Capacity.

Physical Interconnection Facility Study

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

AF2-404 will interconnect with the Dominion transmission system tapping the Gladys DP to Stonemill Switching Station 69 kV line, sharing interconnection facilities with AE2-185.

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 AF2-404 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 AE2-185/AF2-404

Security has been calculated for the AE2-185/AF2-404 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 by tapping the Gladys DP-Stonemill Switching Station 69 kV Line 35. 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.

Project Developer has elected the option Option to Build where they will assume responsibility for the design, procurement and construction of the Transmission Owner Interconnection Facilities and/or Stand-Alone Network Upgrades identified in this Phase III SIS report.

The Project Developer must fulfill additional requirements in accordance to PJM Manual 14C, section 5.1 and PJM Manual 14H, section 8.6.2.

The cost estimates for eligible facilities and Option to Build oversight are highlighted below:

Based on the scope of work for the Interconnection Facilities, it is expected to take 42 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.

Note 1: A Common Use Upgrade is a Network Upgrade that is needed for the interconnection of Generating Facilities or Merchant Transmission Facilities of more than one Project Developer or Eligible Customer and which is the shared responsibility of each Project Developer or Eligible Customer. If multiple Project Developers request to connect to the same interconnection substation, the Transmission Owner will determine the cost to accommodate all the requests at the substation. The cost for the interconnection will be allocated in proportion to the number of required terminations into the substation.

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 AF2-404 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.

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 for Dynamic Stability Analysis Using PSSE

New Service Requests (projects) in PJM Transition Cycle 1 Cluster 35 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 35 projects.

Table 1: Transition Cycle 1 Cluster 35 Projects

This analysis is effectively a screening study to determine whether the addition of the Cluster 35 projects will meet the dynamics requirements of the NERC, Dominion Energy, and PJM reliability standards.

The load flow case finalized for Phase 2 was used as a starting point and was updated based on latest Cluster 35 data, Dominion Energy recommended transmission changes and withdrawn generation. Projects in vicinity of Cluster 35 have been dispatched online at maximum power output with near unity power factor measured at the high-side of the main substation transformer. The dynamic models for Cluster 35 projects were updated based on the latest DP2 data and include any tuning adjustments recommended during Phase 2.

For Cluster 35 the dispatch of the study units was based on two scenarios.

• Scenario 1: MFO met with solar generation and energy storage offline (solar output = 61.9 MW and storage is offline)
• Scenario 3: MFO met with the solar generation and energy storage dispatched proportionally to their power capability (solar output = 47.44 MW and storage output = 14.56 MW)

Cluster 35 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. 75 contingencies were studied, each with a 30 second simulation time period. The studied contingencies included:

• Steady-state operation
• 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 summer peak case:

• Cluster 35 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
• The system with Cluster 35 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local modes.
• Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus) and the final voltages are within the steady-state voltage ranges below per Dominion Energy and AEP’s transmission planning criteria.
• Dominion Energy:
• 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
• AEP:
• 0.92 p.u. to 1.05 p.u. for all voltage levels for each NERC Category Contingency
• No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

The results of the analysis indicated all evaluation criteria were met. The following observations were made.

The initial results showed that Cluster 35 generators units exhibited slow reactive power recovery for several contingencies, Power Plant Controller (PPC) freezing, divergence and low frequency controller oscillations. These issues did not cause instability, and the generating units were tuned to achieve a faster recovery with better response.

The following adjustments were required for the respective queue projects based on the analysis results:

• For AE2-187 the following adjustments were made:
• The REECA1 Vup (p.u.) (CON J+1) parameter was set to 1.15 p.u to mitigate PPC freezing
• Generator tripped for overvoltage protection model for voltage above 1.21 p.u and the time delay setting was updated from 0.16 to 0.3 seconds to allow generator to ride through the fault

• For AE2-283 the following adjustments were made:
• The REGCA1 Accel (CON J+13) parameter was set to 0.5 to improve PSS/E network solution calculations

• For AC1-122 the following adjustments were made:
• The REPCA Ki (CON J+2) parameter was changed from 0 to 10 to improve reactive power recovery

During phase 3 analysis all generations near Cluster 35 (AC1-042, AC1-145, AE2-185, AE2-187, and AF2-404) have their REGCA1 Accel set to 0.7. This was implemented as part of a phase 2 observation.  It should be noted that this parameter does not affect the performance or recovery of the renewable model, but is used to smooth the voltage and angle calculations within PSS/E.

Voltages above 1.05 p.u. were observed at Altavista 69 kV. This is due to Altavista 138-69 kV load tap changer operating at 1.10 p.u. to maintain the Altavista 69 kV scheduled voltage. A significant voltage drop was observed between Altavista, Gladys Tap, Altavista DP, and Mt Airy Tap due to the amount of generation served within the Altavista 69 kV system. To ensure that the post contingency voltage is below 1.05 p.u., the Altavista 138/69 kV load tap changing transformer would need to operate at 1.0375 p.u. tap and under System Normal (P0) conditions, would produce a 0.968 p.u. voltage on the Altavista 69 kV bus, which is within Dominion Energy’s P0 voltage levels. A voltage coordination study is recommended in the future to determine an acceptable voltage schedule for the Altavista 138/69 kV load tap changing transformer to coordinate with the generations served in the Altavista 69 kV system.

AE2-185, AF2-404, AE2-283, AC1-042 and AE2-187 were observed to have controller oscillations for a few faults such as P415. This is not a concern, and IC can tune their model to eliminate this behavior.

AD1-131, and AF2-107’s reactive power was observed to not settle within the 30 second simulation window for various faults. This issue did not cause instability in the system and the models can be tuned to achieve a faster reactive power output settlement.

Low-frequency oscillations were observed for AE1-250 that were positively damped and settled in less than 15 seconds.  This issue did not cause instability in the system.

The AE2-185 queue project met the 0.95 lagging and leading power factor measured at the high side of main transformer.

The AE2-185 and AF2-404 BESS queue projects combined met the 0.95 lagging and leading power factor measured at the high side of main transformer.

The AE2-283 queue project met the 0.95 lagging and leading power factor measured at the high side of main transformer.

A voltage coordination study and Electromagnetic Transients (EMT) study around Altavista is recommended due to the findings of this analysis.  Additionally, any future projects connecting near Altavista should provide EMT models for their facility.

No mitigations were found to be required

Executive Summary for Dynamic Stability Analysis Using  PSCAD/EMT

Model Quality Testing Report

PSCAD model for Queue project AE2-185/AF2-404 and AE2-283 was developed and tested individually to ensure the model was in compliance with the PJM requirements. Test summary and result of test been summarized below in table 2. it is confirmed that PSCAD model was set up properly and satisfied the PJM requirement.

Table 2. MQT Result for each project

Weak Grid Assessment

This Weak Grid Assessment evaluates three projects from PJM Transition Cycle 1 (TC1) Cluster 35 for risk of voltage instability due to weak grid conditions in an EMT simulation environment.  The three projects, AE2-185, AF2-404, and AE2-283, were identified in the Cluster Study as having potential risk of weak grid instability during contingency conditions after dynamic simulation analysis in PSS/E. System reinforcement was found to not be required, although evaluation using detailed models in an EMT simulation was recommended.

This assessment, completed by INS Engineering, aims to evaluate the risk of weak grid instability due to low short circuit ratio as identified in the Cluster Study, using detailed models in an EMT simulation.  A summary description of each project can be found below:

Table 3. Summary Description of TC1 Cluster 35 Projects

Individual project PSCAD models were evaluated for data consistency and model performance as part of the standard Model Quality Test process,  model updates being made where needed.  INS confirmed that the PSCAD models were set up properly and satisfied the requirements of PJM. After satisfactory configuration and performance of the individual projects were obtained, the models were integrated into a translated reduced network in PSCAD to create an overall detailed system model. 

Two representative contingency cases from the Cluster Study, considered effectively the worst case in terms of risk for weak grid instability, were then simulated in the PSCAD detailed system model. For Cluster 35, the following contingency cases were chosen (all projects operating at rated power pre-fault).

• Fault ID: P1.01: Fault at Stone Mill 69 kV on Gladys DP 69 kV and loss of circuit line #35
• Fault ID: P1.18: Fault at Altavista 138 kV on New London (APCO) 138 kV and loss of circuit line #13

Simulation results in PSCAD are summarized below.  It can be observed that in case P1.01 the islanded condition results in the projects tripping, similar to the Cluster Study.  Overall system recovery as observed from the remaining 138kV network is stable.  In P1.18, stable recovery is observed in PSCAD and is consistent with the results of the Cluster Study. 

Table 4. Summary of cases tested in PSCAD system study

The results of this weak grid assessment using PSCAD show overall stable system recovery in the two worst-case contingencies and supports the conclusion from the Cluster Study that mitigation's are not required.

The AE2-185 and AF2-404 BESS queue projects combined met the 0.95 lagging and leading power factor measured at the high side of main transformer.

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.

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.

In accordance with PJM Tariff Part VII, Subpart D, section 312.A.1.b and as outlined in PJM Manual 14H, Section 13, in Phase III of the Cycle, PJM coordinates with the Affected System Operators to conduct any studies required to determine the impact of the New Service Request on any Affected System and will include the Affected System Study results in Phase III System Impact Study, if available from the Affected System Operator.

If your project required an Affected System Study, the results are shown below from the Affected System Operator.

For more details, please refer to your Affected System Study report by the Affected System Operator. If the Affected System Operator identified the need for a system reinforcement on their system due to their planning criteria, Project Developer must follow the Affected System Operator Tariff for construction of the network upgrade. PJM will list any required network upgrades identified by the Affected System Operator in the PJM Project Developer’s GIA under Schedule F.

Affected System network upgrade costs are included in the Adverse Study Impact calculation for DP3. See the Adverse Test Eligibility section of this Phase III SIS report.

No cost allocated system reinforcements were identified for this project in the Phase III System Impact Study load flow analysis.

AF2-404 One Line Diagram