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 Aurora Generation, LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is Commonwealth Edison 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).

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.

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:

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 an uprate to a planned/existing Natural Gas/Storage facility located in the Commonwealth Edison Company zone — Not Specified County, Illinois. This project is an increase to the developer’s AC1-109/AC1-110/AC1-111/AG1-513 project(s), which will share the same Point of Interconnection. The AH1-563 project is a 150.0 MW uprate (150.0 MW Capacity uprate) to the previous project(s). The total installed facilities will have a capability of 1206.0 MW with 250.0 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.

AH1-563 will interconnect on the Commonwealth Edison Company  transmission system at the Aurora E.C. 138 kV Substation.

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 AH1-563 project has the following allocation of costs for interconnection. The cost contribution towards Readiness Deposit #3 are also shown below.

* 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.

Per Tariff Part VII, Subpart D, section 311 (Decision Point II) A.1.b and PJM Manual 14H, section 6.2, Readiness Deposit #3 (RD3) are funds committed by the Project Developer or Eligible Customer based upon the applicable contribution to Network Upgrades as defined below. Readiness Deposits are not used to fund studies nor to offset Security.

During Decision Point II (DP2), the Project Developer or Eligible Customer is required to submit Readiness Deposit #3, which is calculated as 20% of cost allocation for required Phase II Network Upgrades minus Readiness Deposit #1 & Readiness Deposit #2.

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

Note 2: Readiness Deposit #1 (RD1) = ($4,000 * Project Size (MW))

Note 3: Readiness Deposit #2 (RD2) = 10% of cost allocation for required Network Upgrades minus RD1. Readiness Deposit #2 (RD2) can be zero, but may not be a negative number.

Note 4: Readiness Deposit #3 can be zero, but may not be a negative number.

Readiness Deposit #3 Due for Project AH1-563

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.

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.

If your project relies on Transmission Owner Interconnection Facilities, Stand Alone Network Upgrades, and/or Network Upgrades that will be constructed by another New Service Request and the other New Service Request withdraws, the scope and costs will be allocated to your project.

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

Developer Build Option

(No Developer Build Option for this project.)

Based on the scope of work for the Interconnection Facilities, it is expected to take a range of 1 to 30 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.

Notes on Cost Estimate:

1. These estimates are order-of-magnitude estimates of the costs that ComEd would bill to the Project Developer for this interconnection. These estimates are based on a one-line electrical diagram of the project and the information provided by the Project Developer.
2. There were no site visits performed for these estimates. There may be costs related to specific site related issues that are not identified in these estimates. The site reviews will be performed during the Facilities Study or during detailed engineering.
3. These estimates are not a guarantee of the maximum amount payable by the Project Developer and the actual costs of ComEd's work may differ significantly from these estimates. The Project Developer will be responsible for paying actual costs of ComEd's work in accordance with the PJM Open Access Transmission Tariff.
4. The Project Developer is responsible for all engineering, procurement, testing and construction of all equipment on the Project Developer’s side of the Point of Change in Ownership.

No Transmission Owner impacts identified.

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

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.

Analysis Complete - No Issues

Executive Summary:

New Service Requests (projects) in PJM Transition Cycle 2, Cluster 57 are listed in Table 1 below. This report will cover the dynamic analysis of Cluster 57 projects.

This analysis is effectively a screening study to determine whether the addition of the Cluster 57 projects will meet the dynamics requirements of the NERC, COMED and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2028 summer peak load and light load case, modified to include applicable projects. Cluster 57 projects have been dispatched online according to the scenarios, and the voltage schedule is set to achieve near unity power factor at the high side of the main transformer for the IBR projects.

Cluster 57 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 632 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

1. Steady-state operation (20 second run);
2. Three-phase faults with normal clearing time;
3. Three-phase bus faults with normal clearing time;
4. Three-phase to ground faults with three-phase delayed clearing due to a stuck breaker (GO breakers);
5. Three-phase to ground faults with single-phase delayed clearing due to a stuck breaker (IPO breakers)
6. Three-phase faults placed at 80% of the line with delayed (Zone 2) clearing at line end remote from the fault due to primary communications/relay failure;
7. Three-phase faults with loss of multiple-circuit tower line.

For all simulations, the Cluster 57 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 2028 peak load and light load cases:

1. Cluster 57 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),
2. The system with Cluster 57 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.
3. 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).
4. No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

AG2-453, AG2-524, AH1-165, AH1-563, AH1-673, AH1-698 and AH1-714 meets the leading and lagging PF requirement.

Initial simulations identified slow terminal voltage and reactive power control response at AH1-165 due to the absence of reactive power droop in the voltage controller of the power plant controller model (REPCA1). This was resolved by adding a 5% droop to Q/V controller in the REPCA1 model as follows:

REPCA1:

• CON(J+8) = 0.05 (Kc, Reactive current compensation gain (pu))

Contingencies P4.01, P4.02, P4.03, P4.04, P4.05, P4.06, P4.229, P4.230, P4.267, P4.269, P4.270 and P4.279 exhibited oscillations in the POI voltage and generator responses after 17.5s. This behavior is attributed to improperly tuned power system stabilizer model (PSS2C) in AH1-698. This issue was observed only in light load scenario. It is recommended to tune the power system stabilizer to according to the system conditions.

Table 1: TC2 Cluster 57 Projects

Analysis Complete - No Issues

The reactive power capability of AH1-563 meets the 0.95 leading and lagging PF requirement at the high side of the main transformer.

 Steady State Voltage Analysis complete, no voltage issues identified.

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.

NIPSCO: No mitigation required. Rating Of NIPS-
Owned
Line Portion: SN/SE=9015 MVA/9015 MVA.

AEP: No mitigation required. 8348 MVA SN/SE

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

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:

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.

AH1-563 One Line Diagram