AH1-744 meets the criteria for acceleration at Decision Point II (DP2) .

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 Parkway Generation Operating LLC; Parkway Generation Operating, LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Potomac Electric Power Company.

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:

1. 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.
2. PJM will conduct any required voltage analyses.
3. PJM will perform short circuit and stability analyses as required.
4. 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:
1. 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;
2. Include the results of the Affected System Operator’s Affected System Study in the Phase II System Impact Study results, if applicable and available.
5. 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:

1. Verify Interconnection Facilities and Network Upgrades required to accommodate the New Service Request.
2. 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).

This New Service Request meets the criteria for acceleration at Decision Point II (DP2).

Please note that additional requirements apply to accelerated projects at DP2 per PJM Tariff Part VII, Subpart D, section 311. Failure to meet the requirements by the close of DP2 will result in withdrawal.

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:

1. Increase overall by 25% or more
2. 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

The Project Developer has proposed a Natural Gas generating facility located in the Potomac Electric Power Company zone — Prince George's County, Maryland. The installed facilities will have a total capability of 853.5 MW with 48.285 MW of this output being recognized by PJM as Capacity.

Physical Interconnection Facility Study

The transmission owner has not completed a Physical Interconnection Facilities Study for this project.

AH1-744 will interconnect at the Potomac Electric Power Company (PEPCO) transmission system by tapping X4-035/Z1-052 tap 500 kV. 

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 AH1-744 project has the following allocation of costs for interconnection.

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.

A summary of this New Service Requests costs are summarized in the Cost Summary section, herein. Final security will be shown in the Generation Interconnection Agreement (GIA).

No Transmission Owner Interconnection Facilities or Physical Network Upgrades are required for this project.

No impacts identified by Transmission Owner.

The developer is responsible for all design and construction related activities on the developer’s side of the Point of Change in Ownership. PEPCO 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.

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.

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.

Analysis Complete - No Issues

Executive Summary SP Analysis:

New Service Requests (projects) in PJM Transition Cycle 2, Cluster 91 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 91 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 91 projects will meet the dynamics requirements of the NERC, PEPCO, and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2028 summer peak load case, modified to include applicable projects. Cluster 91 projects have been dispatched online at maximum power output, with 1.0 pu voltage at the terminal bus.

Cluster 91 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. A steady-state condition and 224 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run); (and with unsuccessful high-speed reclosing),
2. Three-phase faults with normal clearing time;
3. Single-phase bus faults with normal clearing time;
4. Single-phase faults with stuck breaker;
5. Three-phase faults with loss of multiple-circuit tower line; (and with unsuccessful high-speed reclosing).

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the PEPCO 500/230 kV transmission system.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism, with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2028 summer peak load case:

1. Cluster 91 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 91 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.
3. Following fault clearing, all bus voltages recovered to a minimum of 0.7 pu after 2.5 seconds (except where protective action isolates that bus).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AG2-618 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer with the addition of a 5 MVAR customer planned capacitor bank.

AH1-552 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer.

AH1-744 meets the 0.9 lagging and 1.0 leading reactive power requirements with the addition of a customer planned 30 MVAR STATCOM device.

AG2-618 exhibited slow reactive power recovery for several contingencies. This issue did not result in system instability. The model was tuned to improve the reactive power settling time by updating the Kc parameter to 0.05 and setting the VCFlag to 0 in the REPCA1 module .

High voltage spikes occurred in the simulations immediately after fault clearing for some of the contingencies studied (i.e., fault where spike is observed). The voltage spike is a known artifact of the WECC generic renewable models as stated in the WECC Solar Plant Dynamic Model Guidelines : “It should be noted that generic dynamic models for inverter-based generator tend to produce a short-duration (a cycle or shorter) voltage spike at fault inception and clearing. These spikes should be ignored in most cases, as they do not represent the performance of actual hardware. They are simply a consequence of the model’s limited bandwidth, integration time step, and the way current injection models interface with the network solution.”

The IPCMD and IQCMD states in the REGCAU model of AG2-618 and AH1-552 showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

No mitigations were found to be required.

Table 1: Transition Cycle 2 Cluster 91 Queues

Executive Summary LL Analysis:

New Service Requests (projects) in PJM Transition Cycle 2, Cluster 91 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 91 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 91 projects will meet the dynamics requirements of the NERC, PEPCO, and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2028 light load case, modified to include applicable projects. Cluster 91 projects have been dispatched online at maximum power output, with 1.0 pu voltage at the terminal bus.

Cluster 91 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. A steady-state condition and 224 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

6. Steady-state operation (20 second run); (and with unsuccessful high-speed reclosing),
7. Three-phase faults with normal clearing time;
8. Single-phase bus faults with normal clearing time;
9. Single-phase faults with stuck breaker;
10. Three-phase faults with loss of multiple-circuit tower line; (and with unsuccessful high-speed reclosing).

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the PEPCO 500/230 kV transmission system.

For all simulations, the queue project under study along with the rest of the PJM system were required to maintain synchronism, with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2028 light load case:

5. Cluster 91 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
6. The system with Cluster 91 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.
7. Following fault clearing, all bus voltages recovered to a minimum of 0.7 pu after 2.5 seconds (except where protective action isolates that bus).
8. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AG2-618 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer with the addition of a 5 MVAR customer planned capacitor bank.

AH1-552 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer.

AH1-744 meets the 0.9 lagging and 1.0 leading reactive power requirements with the addition of a customer planned 30 MVAR STATCOM device.

AG2-618 exhibited slow reactive power recovery for several contingencies. This issue did not result in system instability. The model was tuned to improve the reactive power settling time by updating the Kc parameter to 0.05 and setting the VCFlag to 0 in the REPCA1 module .

High voltage spikes occurred in the simulations immediately after fault clearing for some of the contingencies studied (i.e., fault where spike is observed). The voltage spike is a known artifact of the WECC generic renewable models as stated in the WECC Solar Plant Dynamic Model Guidelines : “It should be noted that generic dynamic models for inverter-based generator tend to produce a short-duration (a cycle or shorter) voltage spike at fault inception and clearing. These spikes should be ignored in most cases, as they do not represent the performance of actual hardware. They are simply a consequence of the model’s limited bandwidth, integration time step, and the way current injection models interface with the network solution.”

The IPCMD and IQCMD states in the REGCAU model of AG2-618 and AH1-552 showed erratic behavior for some contingencies in which these generators have been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

No mitigations were found to be required.

Table 1: Transition Cycle 2 Cluster 91 Queues

AH1-744 meets the 0.9 lagging and 1.0 leading reactive power requirements with the addition of a customer planned 30 MVAR STATCOM device.

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.

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, 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.

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.

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

AH1-744 One Line Diagram