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 Wood Duck Solar LLC, and the Transmission Provider (TP) is PJM Interconnection, LLC (PJM). The interconnected Transmission Owner (TO) is East Kentucky Power Cooperative, Inc..

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 meets 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 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 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 East Kentucky Power Cooperative, Inc. zone — Barren County, Kentucky. This project is an increase to the developer’s AG1-070 project(s), which will share the same Point of Interconnection. The AG1-071 project is a 55.0 MW uprate (37.5 MW Capacity uprate) to the previous project(s). The total installed facilities will have a capability of 100.0 MW with 70.2 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.

AG1-071 will interconnect on the East Kentucky Power Cooperative, Inc. transmission system at the Bon Ayr 69 kV substation.

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 AG1-071 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 AG1-070/AG1-071

Security has been calculated for the AG1-070/AG1-071 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 AG1-071 project is an uprate to AG1-070 and will share the same Point of Change of Ownership with AG1-070.

The scope for AG1-070/AG1-071 includes EKPC will expand its existing Bon Ayr 69 kV substation to accommodate the connection of the PD’s substation facilities to the EKPC transmission system.  EKPC will also construct a 69 kV disconnect switch structure which will be the POI interface.  

The total preliminary cost estimate for the Transmission Owner scope of work (including TOIF and Physical Interconnection Network Upgrades) is given in the table below. These costs do not include CIAC Tax Gross-up.

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

EKPC anticipates that it will take 30 months after the signing of the Generator Interconnection Agreement and the project kickoff call is subsequently held to complete the physical interconnection project upgrades associated with AG1-070.

This assumes no delays due to permitting or environmental issues, and that all necessary outages can be taken as needed to maintain the schedule.

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. EKPC 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 solar generation facility shall provide the Transmission Provider with site-specific meteorological data including:

• Temperature (degrees Fahrenheit)
• Atmospheric Pressure (hectopascals)
• Irradiance
• Forced outage data

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

New Service Requests (projects) AG1-070 and AG1-071 in PJM Transition Cycle 1 are listed in Table 1 below. This report will cover the dynamic analysis of AG1-070 and AG1-071 projects.

This analysis is effectively a screening study to determine whether the addition of the AG1-071 and AG1-071 projects will meet the dynamics requirements of the NERC, EKPC and PJM reliability standards.

The load flow scenario for the analysis was based on the RTEP 2027 summer peak load case, modified to include applicable projects. AG1-070 and AG1-071 have been dispatched online at maximum power output and the voltage schedule set to achieve near unity power factor at the high side of the main transformer.

AG1-070 and AG1-071 projects were tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 121 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a) Steady-state operation (20 second run);

       b) Three-phase faults with normal clearing time;

       c) Single-phase bus faults with normal clearing time;

       d) Single-phase faults with stuck breaker;

       e) Single-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;

       f) Single-phase faults with loss of multiple-circuit tower line.

No relevant high speed reclosing (HSR) contingencies were identified for this study.

For all simulations, the AG1-070 and AG1-071 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 2027 peak load case:

       a) AG1-070 and AG1-071 projects were able to ride through the faults (except for faults where protective action trips a generator(s)),

       b) The system with AG1-070 and AG1-071 projects included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3%.

       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 as a consequence of that fault.

AG1-070 and AG1-071 meet the 0.95 leading and lagging PF requirement.

The IPCMD and IQCMD states in the REGCA1 model of AG1-070 GEN and AG1-071 GEN 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, these plots are ignored.

No mitigations were found to be required.

Table 1: TC1 AG1-070/AG1-071 Projects

The reactive power capability of AG1-071 meets the 0.95 leading and lagging PF requirement at the high side of the 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.

Replace 0.38 miles of 266.8 MCM 26X7 ACSR
conductor in the Campbellsville 2 Tap to Taylor
County section of the Lebanon to Taylor County 69
kV line, using 556 MCM 26X7 ACSR or better
conductor.

Reconductor the 6.58 miles of 266.8 26x7 ACSR and
replace 266.8 26x7 ACSR line riser in the Lebanon
to Springfield 69 kV line with 397.5 MCM ACSR

Reconductor the 0.19 miles of 2/0 7x CU in the
Morehead W to Morehead 69kV, to 266.8 MCM 26x7
ACSR.

Increase the maximum operating temperature of 1.96
miles of 397.5 ACSR in the Shelbyville South to
Shelby Co tap section of the Shelbyville to
Finchville 69 kV line from 150°F to a minimum of
170°F.

Increase the MOT of 3.24 miles of 266.8 26x7 ACSR
to 176/212F in the Springfield-North Springfield
69 kV line.

Reconductor the 556.5 MCM 26X7 ACSR 20.12 mi with
795 MCM 45X7 ACSR or better in the Brown North to
Tyrone 138 kV line.

Based on the Phase III analysis results, this project is contingent on and may have cost responsibility for the following System Reinforcements:

PJM evaluated the impact of topology changing reinforcements to mitigate the impacts driven by New Service Requests. PJM determined which reinforcements were eliminated as a result of modeling the topology changing reinforcements. PJM then grouped the topology changing and eliminated reinforcements by region and computed a discount factor to apply to reinforcements to reduce the cost of all these reinforcements down to the cost of contstructing only the topology changing reinforcements. For additional details, please click the icon below

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.

AG1-071 One Line Diagram