AG2-562 Phase II System Impact Study Report
v1.00 released 2026-06-03 18:56
Elderberry 345 kV
0.0 MW Capacity / 52.0 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 St. Joseph Energy Center, LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is American Electric Power.
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 meets the Adverse Study Impact Criteria and has the option to either move forward in the Cycle process or withdraw at DP2 with Readiness Deposits refunded. See Readiness Deposit 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 an uprate to a planned/existing Natural Gas facility located in the American Electric Power zone — St. Joseph County, Indiana. This project is an increase to the developer’s AB1-080 project(s), which will share the same Point of Interconnection. The AG2-562 project is a 52.0 MW uprate (0.0 MW Capacity uprate) to the previous project(s). The total installed facilities will have a capability of 767.0 MW with 40.0 MW of this output being recognized by PJM as Capacity.Project Information
Physical Interconnection Facility Study
The transmission owner has completed the Physical Interconnection Facilities Study. This report is available for download.
Point of Interconnection
AG2-562 will interconnect on the American Electric Power transmission system at the Elderberry 345 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 AG2-562 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 AG2-562 | Cost Subject to Readiness* | Cost Subject to Adverse |
| Transmission Owner Interconnection Facilities (TOIF) | $0 | $0 | $0 |
| Other Scope | $603,891 | $0 | $0 |
| Option To Build Oversight | $0 | $0 | $0 |
| Physical Interconnection Network Upgrades | |||
| Stand Alone Network Upgrades | $0 | $0 | $0 |
| Network Upgrades | $1,273,714 | $1,273,714 | $1,273,714 |
| 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 | $18,979 | $0 | $18,979 |
| Total | $1,896,584 | $1,273,714 | $1,292,693 |
* 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) = ($4,000 * Project Size (MW))
Note 3: Readiness Deposit #2 (RD2) = 10% of cost allocation for required Network Upgrades minus RD1. Readiness Deposit #2 (RD2) can be zero, but may not be a negative number.
Note 4: Readiness Deposit #3 can be zero, but may not be a negative number.
Readiness Deposit #3 Due for Project AG2-562
Readiness Deposit #3 has been calculated for the project based on the Phase II System Impact Study results and is shown in the table below. This Readiness Deposit #3 must be provided at Decision Point II through either a wire transfer or letter of credit per Manual 14H, Section 6.2.
Readiness Deposit #3 Due for AG2-562
For additional detail regarding Readiness Deposit Refunds, reference PJM Manual 14H, section 6.2.1. The Readiness Deposit Letter of Credit template can be found here.
Transmission Owner Scope of Work
The total preliminary cost estimate for the Transmission Owner scope of work (including TOIF and Physical Interconnection Network Upgrades) is given in the table below. These costs do not include CIAC Tax Gross-up.
Transmission Owner Build Option
| Network Upgrades | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) | AEP Indiana Michigan Transmission Company Inc. will review and revise (as needed) the protective relay settings at the Olive 345 kV Station. | $44,758 | $12,003 | $28,387 | $7,613 | $92,761 | $92,761 |
| (Pending) | IMTCO will tie the proposed AG2-562 345 kV project into Elderberry 345 kV Station by completing the following construction tasks: • Installation of (3) 345KV RCVTs with (3) single-phase 345KV CCVT structures, foundations, and adapter steel. • AEP Indiana Michigan Transmission Company Inc. will install one (1) new 1101 router at the Elderberry 345 kV Station. | $573,364 | $339,769 | $166,344 | $101,476 | $1,180,953 | $1,180,953 |
| Other | |||||||
|---|---|---|---|---|---|---|---|
| RTEP ID | Description | Direct | Indirect | Total Cost ($USD) | Allocated Cost ($USD) | ||
| Labor | Materials | Labor | Materials | ||||
| (Pending) | AEP Indiana Michigan Transmission Company Inc. will install one (1) metering panel with two (2) primary meters and one (1) ethernet switch in the AB1-080 Project Developer's collector Station. | $310,265 | $139,608 | $106,222 | $47,796 | $603,891 | $603,891 |
Developer Build Option
(No Developer Build Option for this project.)
| Build Option Price Comparison | |||||||
|---|---|---|---|---|---|---|---|
| Build Option | Total Cost | Allocated Cost | |||||
| Transmission Owner Build Option | $1,877,605 | $1,877,605 | |||||
| Developer Build Option | (No Developer Build Option) | ||||||
Based on the scope of work for the Interconnection Facilities, it is expected to take 15 month(s) after the signing of a Generator Interconnection Agreement (as this is a FERC connection) and construction kickoff call to complete the installation of the physical connection work. This assumes that there will be no environmental issues with any of the new properties associated with this project, that there will be no delays in acquiring the necessary permits for implementing the defined interconnection work, and that all system outages will be allowed when requested.
Note that the TO findings were made from a conceptual review of this project. A more detailed review of the connection facilities and their cost will be identified in a future study phase. Further note that the cost estimate data provided should be considered high level estimates since it was produced without a detailed engineering review. The Project Developer will be responsible for the actual cost of construction. TO herein reserves the right to return to any issues in this document and, upon appropriate justification, request additional monies to complete any reinforcements to the transmission systems.
Remote Terminal Work: During Phase II of the PJM interconnection process, TO’s System Protection Engineering Department will review transmission line protection as well as anti-islanding required to accommodate the new generation and interconnection substation. System Protection Engineering will determine the minimal acceptable protection requirements to reliably interconnect the proposed generating facility with the transmission system. The review is based on maintaining system reliability by reviewing TO’s protection requirements with the known transmission system configuration which includes generating facilities in the area. This review may determine that transmission line protection and communication upgrades are required at remote substations.
Transmission Owner Analysis
No Transmission Owner impacts identified.
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. AEP 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 AG2-562 was evaluated as a 52.0 MW (0.0 MW Capacity) injection in the AEP area.
AG2-562 was evaluated as part of a plant. The total Energy output of the plant was evaluated at its maximum seasonal capability of 767.0 MW (52.0 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.)
Winter Peak Analysis
The New Service Request AG2-562 was evaluated as a 52.0 MW (0.0 MW Capacity) injection in the AEP area.
AG2-562 was evaluated as part of a plant. The total Energy output of the plant was evaluated at its maximum seasonal capability of 767.0 MW (52.0 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.
| Study | Area | Facility Description | Contingency Name | Contingency Type | DC|AC | Final Cycle Loading | Rating (MVA) | Rating Type | MVA to Mitigate | MW Contribution | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| GD2 | AEP | 05ALLEN-05RPMONE 345.0 kV Ckt 1 line | AEP_P1-2_#7441_100545_SRT-A | Single | AC | 118.4 % | 1737.0 | B | 2056.53 | 4.83 | |
| GD2 | AEP | 05JEFRSO-05JEFRSO 765.0/345.0 kV Ckt 2 transformer | AEP_P4_#6189_05HANG R 765_D1_SRT-A | Breaker | AC | 103.35 % | 3276.0 | B | 3385.78 | 5.27 | |
| GD2 | AEP | 05JEFRSO-05JEFRSO 765.0/345.0 kV Ckt 2 transformer | AEP_P1-2_#709_546_SRT-A | Single | AC | 101.76 % | 3276.0 | B | 3333.77 | 5.29 | |
| GD2 | AEP | 05JEFRSO-05JEFRSO 765.0/345.0 kV Ckt 2 transformer | AEP_P4_#709_05HANG R 765_D2_SRT-A | Breaker | AC | 101.76 % | 3276.0 | B | 3333.74 | 5.29 | |
| GD2 | AEP/OVEC | 05JEFRSO-06CLIFTY 345.0 kV Ckt 1 line | AEP_P4_#6189_05HANG R 765_D1_SRT-A | Breaker | AC | 111.9 % | 2991.0 | B | 3346.96 | 5.27 | |
| GD2 | AEP/OVEC | 05JEFRSO-06CLIFTY 345.0 kV Ckt 1 line | AEP_P1-2_#709_546_SRT-A | Single | AC | 110.0 % | 2991.0 | B | 3290.17 | 5.29 | |
| GD2 | AEP/OVEC | 05JEFRSO-06CLIFTY 345.0 kV Ckt 1 line | AEP_P4_#709_05HANG R 765_D2_SRT-A | Breaker | AC | 110.0 % | 2991.0 | B | 3290.12 | 5.29 | |
| GD2 | AEP | 05MARYSVL_RS-05MARYSV 765.0 kV Ckt Z1 line | AEP_P4_#7334_05JEFRSO 765_A2_SRT-A | Breaker | AC | 113.19 % | 4961.0 | B | 5615.13 | 13.62 | |
| GD2 | AEP | 05MARYSVL_RS-05MARYSV 765.0 kV Ckt Z1 line | AEP_P4_#6189_05HANG R 765_D1_SRT-A | Breaker | AC | 103.69 % | 4961.0 | B | 5144.06 | 12.6 | |
| GD2 | AEP | 05MARYSVL_RS-05MARYSV 765.0 kV Ckt Z1 line | AEP_P4_#1760_05JEFRSO 765_A_SRT-A | Breaker | AC | 103.1 % | 4961.0 | B | 5114.58 | 13.6 | |
| GD2 | AEP | 05MARYSVL_RS-05MARYSV 765.0 kV Ckt Z1 line | AEP_P1-2_#709_546_SRT-A | Single | AC | 102.1 % | 4961.0 | B | 5065.25 | 12.64 | |
| GD2 | AEP | 05MARYSVL_RS-05MARYSV 765.0 kV Ckt Z1 line | AEP_P4_#709_05HANG R 765_D2_SRT-A | Breaker | AC | 102.1 % | 4961.0 | B | 5065.17 | 12.64 |
Light Load Analysis
The New Service Request AG2-562 was evaluated as a 52.0 MW injection
AG2-562 was evaluated as part of a plant. The total Energy output of the plant was evaluated at its maximum seasonal capability of 767.0 MW (52.0 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
Short Circuit Analysis is complete and an overduty has been identified. TC2 project AG2-562 is contributing to the overduty in New Carlisle CB A, which exceeds the >1% threshold per PJM Manual 14H 4.2.3.1.
An existing supplemental project, S2851, upgrades the overdutied breaker. AG2-562 is contingent on this upgrade.
Below is the duty impact analysis.
Bus Name | Bus Number | Project ID | Breaker Overdutied | Breaker Capacity (Amps) | Duty Percent With TC2 (%) | Duty Amps With TC2 (Amps) | Full Amps Contribution | Reinforcement ID | Reinforcement Project Description |
05NEW CARLI1 138. kV | 243349 | AG2-562 | A | 40000 | 101.84% | 40736 | 572.9 | S2851 | Replace 138kV circuit breaker A with a new 3000A 63kA circuit breaker |
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
Analysis Complete - No Issues
Executive Summary
New Service Requests AG2-230, AG2-562, AH1-153 and AH1-272 in PJM Transition Cycle 2 Cluster 40 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 40 projects.
This analysis is effectively a screening study to determine whether the addition of the Cluster 40 projects will meet the dynamics requirements of the NERC, AEP and PJM reliability standards.
The load flow scenario for the analysis was based on the RTEP 2028 Summer Peak, modified to include applicable projects. Cluster 40 projects have been dispatched online at maximum power output, with 1.0 voltage at the terminal bus.
Transition Cycle 2 Cluster 40 will be tested for compliance with NERC, PJM and other applicable criteria. The contingencies will be studied with a 20 second simulation time. Contingencies to be studied include:
a) Steady-state operation (Category P0);
b) Three-phase faults with normal clearing time (and with unsuccessful high-speed reclosing) (Category P1);
c) Single-phase bus faults with normal clearing time (Category P2);
d) Single-phase faults with stuck breaker (Category P4);
e) Three-phase faults with loss of multiple-Circuit tower line; (and with unsuccessful high-speed reclosing) (Category P7).
High Speed Reclosing (HSR) facilities were found in the vicinity of TC2 Cluster 40 projects.
Prior outage scenarios will not be considered for this study.
For all simulations, the queue project 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 the fault contingencies tested on the 2028 Summer Peak case:
a) Cluster 40 projects were able to ride through the faults (except for faults where protective action trips a generator(s)).
b) The system with Cluster 40 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.
c) 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).
d) No transmission element tripped, other than those either directly connected or designed to trip because of that fault.
In several contingencies, AH1-153 active power failed to recover to the pre fault level. Although this issue did not cause instability in the system, the model was tuned to achieve satisfactory active power recovery. This was accomplished by adjusting the Kp, Ki, and Kc in the plant controller model (REPCA1) by setting Kp from 3 to 5, Ki from 5 to 3, and Kc from 0 to 0.065. The parameters modification is pending developer’s confirmation.
The IPCMD and IQCMD states in the REGCA1 models of AG2-230 showed erratic behavior for some contingencies in which AG2-230 has been disconnected as part of the contingency event. Since the machines are 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.
The IPCMD and IQCMD states in the REGCA1 models of AH1-153 showed erratic behavior for some contingencies in which AH1-153 has been disconnected as part of the contingency event. Since the machines are 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.
The IPCMD and IQCMD states in the REGCA1 models of AH1-272 showed erratic behavior for some contingencies in which AH1-272 has been disconnected as part of the contingency event. Since the machines are 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 40 Projects |
|
|
|
|
Project | Fuel Type | Transmission Owner | MFO (MW) | Point of Interconnection |
AG2-230 | Solar | AEP | 150 | Dumont substation 345 kV |
AH1-153 | Solar | AEP | 50 | Dumont substation 345 kV |
AG2-562 | Natural Gas | AEP | 52 | Elderberry station 345 kV |
AH1-272 | Solar | AEP | 185 | Twin Branch – Argenta 345 kV |
Reactive Power Analysis
The reactive power capability of AG2-562 meets the 1.00 leading and 0.90 lagging power factor at the generator terminals.
.
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.
| New Service Requests Dependencies | ||
|---|---|---|
| Project ID | Project Name | Status |
| AA1-018 | Powerton-Goodings Grove | In Service |
| AB1-006 | Meadow Lake 345kV | In Service |
| AB2-070 | Mt. Pulaski-Brokaw | In Service |
| AC1-033 | Kewanee 138 kV | In Service |
| AC1-053 | Lanesville-Brokaw | In Service |
| AC1-168 | Kewanee-Streator | Suspended |
| AC1-214 | Crescent Ridge | In Service |
| AD1-100 | Loretto-Wilton 345 kV & Braidwood-Davis Creek 345 kV | Under Construction |
| AD2-038 | Powerton-Nevada 345 kV | Under Construction |
| AD2-047 | Davis Creek 138 kV | Suspended |
| AD2-066 | Mazon-Crescent Ridge 138 kV | Under Construction |
| AD2-100 | Kincaid-Pana 345 kV | Suspended |
| AD2-131 | Kincaid-Pana 345kV | Suspended |
| AD2-134 | Shady Oaks | Partially in Service - Under Construction |
| AE1-113 | Mole Creek 345 kV | Under Construction |
| AE1-114 | Maryland-Lancaster 138 kV | Engineering & Procurement |
| AE1-163 | Powerton-Nevada 345 kV | Under Construction |
| AE1-166 | Loretto-Wilton 345 kV & Braidwood-Davis Creek 345 kV | Engineering & Procurement |
| AE1-172 | Loretto-Wilton Center | Withdrawn |
| AE1-205 | McLean 345 kV | Engineering & Procurement |
| AE2-045 | Olive-Reynolds 345 kV | Engineering & Procurement |
| AE2-152 | Loretto-Wilton 345 kV & Braidwood-Davis Creek 345 kV | Engineering & Procurement |
| AE2-223 | McLean 345 kV | Engineering & Procurement |
| AE2-255 | Molecreek 345 kV | Under Construction |
| AE2-261 | Kincaid-Pana 345 kV | Engineering & Procurement |
| AE2-281 | Powerton-Nevada 345 kV | Under Construction |
| AE2-341 | Sandwich-Plano 138 kV | Engineering & Procurement |
| AF1-030 | Sandwich-Plano 138 kV | Engineering & Procurement |
| AF1-090 | Kincaid-Pana | Engineering & Procurement |
| AF1-158 | Edison-Gravel Pit 138 kV | In Service |
| AF1-207 | Reynolds-Olive #1 345 kV | Engineering & Procurement |
| AF1-215 | Olive-Reynolds 345 kV | In Service |
| AF1-296 | Garden Plain 138 kV | Engineering & Procurement |
| AF1-322 | Meadow Lake 345 kV | Under Construction |
| AF2-032 | Kincaid 345 kV | Withdrawn |
| AF2-041 | Nelson-Electric Junction 345 kV | Engineering & Procurement |
| AF2-078 | Reynolds-Olive #1 345 kV | Engineering & Procurement |
| AF2-132 | Reynolds-Olive #1 345 kV | Under Construction |
| AF2-133 | Reynolds-Olive #2 345 kV | Under Construction |
| AF2-134 | Olive-Reynolds #2 345 kV | In Service |
| AF2-142 | Nevada 345 kV | Engineering & Procurement |
| AF2-143 | Powerton-Nevada 345 kV | Engineering & Procurement |
| AF2-199 | Nelson-Electric Junction 345 kV | Engineering & Procurement |
| AF2-200 | Nelson-Electric Junction 345 kV | Engineering & Procurement |
| AF2-205 | Olive-Reynolds #2 345 kV | Engineering & Procurement |
| AF2-225 | McLean 345 kV | Engineering & Procurement |
| AF2-252 | Blue Mound 345 kV | Engineering & Procurement |
| AF2-350 | Kensington 138 kV | Engineering & Procurement |
| AF2-352 | Blue Mound 345 kV | Engineering & Procurement |
| AF2-359 | Olive-University Park 345 kV | Engineering & Procurement |
| AG1-118 | Sugar Grove-Waterman 138kV | Engineering & Procurement |
| AG1-127 | Crego Rd 138 kV | Engineering & Procurement |
| AG1-226 | Dequine-Eugene 345 kV | Engineering & Procurement |
| AG1-237 | Dequine-Eugene 345 kV | Engineering & Procurement |
| AG1-302 | Olive-Reynolds #1 345 kV | Under Construction |
| AG1-349 | Olive-Reynolds #2 345 kV | Engineering & Procurement |
| AG1-374 | Blue Mound 345 kV | Engineering & Procurement |
| AG1-436 | Olive-University Park 345 kV | Engineering & Procurement |
| AG1-447 | Olive-University Park 345 kV | Engineering & Procurement |
| AG1-460 | Kincaid-Pana 345 kV | Engineering & Procurement |
| AG1-462 | Cordova 345 kV | Engineering & Procurement |
| AG1-478 | Wilmington 34.5 kV | Engineering & Procurement |
| AG1-555 | Dequine 345 kV | Engineering & Procurement |
| AG2-061 | Dana 345 kV | Active |
| AG2-114 | Dresden-Pontiac Midpoint 345 kV | Active |
| AG2-163 | Dequine-Eugene 345 kV | Active |
| AG2-245 | Olive - Reynolds #1 345 kV | Active |
| AG2-363 | Powerton 345 kV | Active |
| AG2-364 | Powerton 345 kV | Active |
| AG2-453 | Lasalle - Plano 345 kV | Active |
| AG2-491 | Meadow Lake 345 kV | Active |
| AG2-516 | Pecatonica 138kV | Active |
| AG2-524 | LaSalle Station - Mazon 138 kV | Active |
| AG2-585 | Kensignton 138kV | Active |
| AG2-660 | Nelson-Electric Junction 345 kV | Active |
| AG2-675 | Cordova 345 kV | Active |
| AH1-044 | Nelson - Electric Junction 345 kV | Active |
| AH1-150 | Nelson-Electric Junction 345 kV | Active |
| AH1-151 | Nelson-Electric Junction 345 kV | Active |
| AH1-196 | Silver Lake - Cherry Valley 345 kV | Active |
| AH1-302 | Olive - Reynolds 345 kV | Active |
| AH1-338 | New Sub S2354 138kV | Active |
| AH1-341 | ESS-H445 3B 138kv | Active |
| AH1-392 | Gravel Pit-Kankakee 138 kV | Active |
| AH1-482 | Olive - Reynolds #2 345 kV | Active |
| AH1-541 | Chestnut 345 kV | Active |
| AH1-543 | Mulberry - Tazewell 345 kV | Active |
| W2-048 | Brokaw-Lanesville | In Service |
| W4-005 | Blue Mound-Latham | In Service |
| X2-022 | Brokaw-Lanesville | In Service |
| X2-052 | Dumont-Olive 345kV | In Service |
| Z2-087 | Pontiac MidPoint-Brokaw 345kV | In Service |
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.
| Impacted Facility | Transmission Owner | Reinforcement | Cost | Cost Allocated to AG2-562 | Scenarios |
|---|---|---|---|---|---|
| NIPS | Reynolds-Greentown 765 kV NIPSCO: No mitigation required. Rating Of NIPS- Owned Line Portion: SN/SE=9015 MVA/9015 MVA. AEP: No mitigation required. 8348 MVA SN/SE | $0 | $0 |
|
| NIPS | Wvrich - Rochester TP 69 kV DEI: Rebuild 1 mile of 69kV with 477ACSR/VR2 @ 100/120C the ratings assume that NIPSCO terminal upgrades would not limit our T-Line rating. $1.5M NIPSCO: DEI mitigations acceptable to remove constraint. $0 | $1,500,000 | $18,979 |
|
System Reinforcements
Based on the Phase II System Impact Study analysis results, this project is contingent on and may have cost responsibility for the following System Reinforcements:
| TO | RTEP ID | Title | Category | Allocated Cost ($USD) | Facilities Study |
|---|---|---|---|---|---|
| AEP | s2851 | New Carlisle 138 kV station | Contingent | $0 | N/A |
| Grand Total: | $0 | ||||
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: s2851
- Type
- Short Circuit
- TO
- AEP
- RTEP ID / TO ID
- s2851 / S2851
- Title
- New Carlisle 138 kV station
- Description
- New Carlisle 138 kV station: Replace 138kV circuit breaker A with a new 3000A 63kA circuit breaker.
- Cost Information
- Time Estimate
- TBD
Contingent Note: Although AG2-562 may not presently have cost responsibility for this upgrade, AG2-562 may need this upgrade in-service to be deliverable to the PJM system. If AG2-562 desires to come into service prior to completion of the upgrade, the Project Developer will need to request PJM to perform an interim study to determine if they would be deliverable for all or a portion of their output for each delivery year until the upgrade is complete.
System Reinforcement: b4068.1
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b4068.1 / AEP-TC2-18693
- Title
- b4068: Greentown 765 kV - Teddy 765kV - Marysville 765 kV - Greenfield Line - AEP Proposal 570
- Description
- b4068.1 through b4068.49: Affected Transmission Owners: AEP / Dayton / ATSI The objective of this project is to construct multiple transmission lines to address Ohio area violations. The total distance covered by the lines is approximately 359.54 miles. The first transmission line ranges from the existing Greentown Substation in Howard County, Indiana to the new Teddy Substation in Clark County, Ohio, the line then branches north towards the existing Marysville Substation in Union County, Ohio, and east to the existing Beatty Substation in Franklin County, Ohio, and then extends to the existing Cole Substation in Franklin County, Ohio. The second transmission line extends from the existing Adkins Substation in Pickaway County, Ohio, to the new West Millersport Substation in Fairfield County, Ohio, then continues to the existing Conesville Substation in Coshocton County, Ohio before finally extending to the existing Guernsey Substation in Guernsey County, Ohio. There is a total of five transmission lines that extend between unnamed substations (Hayden - Cole 345 kV, Hyatt - Maliszewski 345 kV [double circuit], Roberts - Kenny 138 kV, Wilson - 5th Avenue 138 kV, West Millersport-Kirk 345 kV). This project will traverse 4 counties (Howard, Grant, Blackford, Jay) in Indiana, and 13 counties (Darke, Shelby, Champaign, Clark, Madison, Franklin, Delaware, Pickaway, Fairfield, Licking, Muskingum, Coshocton, Guernsey) in Ohio. This proposal has a total of 38 components, including 16 substation upgrade components, two greenfield substation components, eight greenfield transmission line components covering approximately 336.2 miles, and 12 transmission line upgrade components covering approximately 23.34 miles. b4068.28/b4068.49 is dependent on b3919.1 Baseline completion.
- Cost Information
- Time Estimate
- Jun 01 2030
Not ContingentTopology Changing Note 1: AG2-562 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AG2-562 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 | ||
|---|---|---|---|
| 05JEFRSO-05JEFRSO 345.0/765.0 kV Ckt 2 transformer | (Any) | No new ratings for this Flowgate. | |
| 05JEFRSO-06CLIFTY 345.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. | |
| 05MARYSV-05MARYSVL_RS 765.0 kV Ckt Z1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b3919.1
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3919.1
- Title
- Reconfigure Maliszewski 765 kV station and establish 345 kV breaker yard
- Description
- Reconfigure Maliszewski 765 kV station from 2 breakers to a 6 breaker ring bus. Install a new 765/345 kV transformer. Establish new 345 kV breaker yard with 3 string breaker and a half to include a line exit to Hyatt and a line exit to Corridor. Loop the existing Hyatt - West Millersport 345 kV line into the new established 345 kV yard at the Maliszewski station.
- Cost Information
- Time Estimate
- Jun 01 2029
Not ContingentTopology Changing Note 1: AG2-562 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AG2-562 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 | ||
|---|---|---|---|
| 05JEFRSO-05JEFRSO 345.0/765.0 kV Ckt 2 transformer | (Any) | No new ratings for this Flowgate. | |
| 05JEFRSO-06CLIFTY 345.0 kV Ckt 1 line | (Any) | No new ratings for this Flowgate. | |
| 05MARYSV-05MARYSVL_RS 765.0 kV Ckt Z1 line | (Any) | No new ratings for this Flowgate. |
System Reinforcement: b3878.1
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3878.1
- Title
- Upgrade 765 kV circuit breakers 'B' and 'B2' to 5000A 50kA breakers at Marysville Station
- Description
- Upgrade 765 kV circuit breakers 'B' and 'B2' to 5000A 50kA breakers at Marysville Station. In addition, the project will upgrade the existing wavetrap towards Sorenson.
- Cost Information
- Time Estimate
- Nov 12 2027
Not Contingent Note: AG2-562 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AG2-562 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 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 05MARYSV-05MARYSVL_RS 765.0 kV Ckt Z1 line | (Any) |
|
System Reinforcement: b3851.1
- Type
- Load Flow
- TO
- AEP
- RTEP ID / TO ID
- b3851.1 / B3851.1
- Title
- Rebuild Allen-RP Mone 345kV
- Description
- Rebuild Allen –R.P. Mone 345kV line (18.6 miles).
- Cost Information
- Time Estimate
- Jun 01 2027
Not Contingent Note: AG2-562 contributes to the loading of an overloaded facility that is being mitigated by a planned baseline upgrade. AG2-562 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 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 05RPMONE-05ALLEN 345.0 kV Ckt 1 line | (Any) |
|
Attachments
AG2-562 One Line Diagram
