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Siemens Industry, Inc. Siemens Power Technologies International 10900 Wayzata Boulevard Minnetonka, Minnesota 55305 USA Tel: +1 (952) 607-2270 • Fax: +1 (518) 346-2777 www.siemens.com/power-technologies

Siemens PTI Report R017-20

Interconnection System Impact Study Request 36 Coggon

Prepared for Central Iowa Power Cooperative Submitted by: Douglas Brown, Senior Manager William Wang, Senior Consultant Abhishek Dinakar, Consultant Swati Rath, Consultant March 5, 2020 Siemens PTI Project 62OT-001705

Filed with the Iowa Utilities Board on April 30, 2021, GCU-2021-0001

http://www.siemens.com/energy/power-technologies

Revision History

Date Rev. Description

February 19, 2020 0 Initial Draft.

March 5, 2020 1 Report issued to CIPCO


i

Siemens Industry, Inc. – Siemens Power Technologies International R017-20 – Rev. 1 – Interconnection System Impact Study Request 36 Coggon

Contents Legal Notice ................................................................................................................. iii

Section 1 – Executive Summary ............................................................................ 1-1

1.1 Mitigation Summary ...............................................................................................1-1

1.2 Steady State Contingency Analysis ......................................................................1-2

1.3 Reactive Power Requirements ..............................................................................1-2

1.4 Short Circuit Analysis .............................................................................................1-2

1.5 Short Circuit Ratio ..................................................................................................1-3

1.6 Voltage Stability Analysis .......................................................................................1-3

1.7 Transient Stability Analysis ....................................................................................1-3

Section 2 – Introduction ......................................................................................... 2-1

Section 3 – Steady State Analysis ........................................................................ 3-1

3.1 Study Methodology ................................................................................................3-1

3.2 Case Development ................................................................................................3-1

3.3 Contingency Criteria ..............................................................................................3-2

3.4 Monitored Elements ...............................................................................................3-3

3.5 Performance Criteria ..............................................................................................3-4

3.5.1 CIPCO .....................................................................................................3-4

3.5.2 MISO ........................................................................................................3-4

3.5.3 SPP ..........................................................................................................3-4

3.5.4 PJM ..........................................................................................................3-5

3.5.5 AECI ........................................................................................................3-5

3.6 Contingency Analysis Results ...............................................................................3-5

3.6.1 Summer Peak ..........................................................................................3-5

3.6.2 Summer Shoulder....................................................................................3-6

3.7 Network Upgrades .................................................................................................3-6

3.8 Reactive Power Requirements ..............................................................................3-9

3.8.1 Methodology ............................................................................................3-9

3.8.2 Results .................................................................................................. 3-10


Contents


ii

Section 4 – Short Circuit Analysis ........................................................................ 4-1

4.1 Methodology ..........................................................................................................4-1

4.2 Short Circuit Database ...........................................................................................4-1

4.3 Short Circuit Analysis Results ................................................................................4-1

4.4 Short Circuit Ratio ..................................................................................................4-5

Section 5 – Voltage Stability Analysis .................................................................. 5-1

Section 6 – Transient Stability Analysis ............................................................... 6-1

6.1.1 Study Methodology ..................................................................................6-1

6.1.2 Case Development ..................................................................................6-1

6.1.3 Contingency Criteria ................................................................................6-2

6.1.4 Performance Criteria................................................................................6-2

6.2 Transient Stability Results .....................................................................................6-4

Appendix A – Case Development ......................................................................... A-1

A.1 Prior Queued CIPCO Projects .............................................................................. A-1

A.2 Network Upgrades for Prior Queued CIPCO Projects ......................................... A-1

A.3 Prior Queued MISO Projects ................................................................................ A-2

A.4 IR36 Power Flow Data .......................................................................................... A-3

A.5 IR36 Short Circuit Data ......................................................................................... A-4

A.6 IR36 Dynamics Data ............................................................................................. A-5

A.7 IR36 Diagram........................................................................................................ A-8

Appendix B – Contingency Analysis Results...................................................... B-1

Appendix C – Short Circuit Analysis Results ...................................................... C-1

Appendix D – Transient Stability Analysis Results ............................................ D-1


iii


Legal Notice This document was prepared by Siemens Industry, Inc., Siemens Power Technologies International (Siemens PTI), solely for the benefit of Central Iowa Power Cooperative. Neither Siemens PTI, nor parent corporation or its or their affiliates, nor Central Iowa Power Cooperative, nor any person acting in their behalf (a) makes any warranty, expressed or implied, with respect to the use of any information or methods disclosed in this document; or (b) assumes any liability with respect to the use of any information or methods disclosed in this document.

Any recipient of this document, by their acceptance or use of this document, releases Siemens PTI, its parent corporation and its and their affiliates, and Central Iowa Power Cooperative from any liability for direct, indirect, consequential or special loss or damage whether arising in contract, warranty, express or implied, tort or otherwise, and irrespective of fault, negligence, and strict liability.


Legal Notice


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1-1


Section

1 Executive Summary This report presents the results of an Interconnection System Impact Study, which was performed to identify the system impacts that would result if the Coggon PV solar generation project were interconnected without system modifications, and to identify network upgrades to enable interconnection of the project. This study covers interconnection service and transmission service on CIPCO to the CIPCO/MISO border. This study does not grant any nor contemplate transmission service or deliverability within the MISO market. Delivery from the CIPCO/MISO border to the MISO market would need to be studied by MISO through a MISO transmission service request or a request for external network resource interconnection service.

The Coggon PV solar generation project is request number 36 (IR36) in the Central Iowa Power Cooperative (CIPCO) generator interconnection queue. The project has requested 100 MW of interconnection service and will interconnect to the CIPCO transmission network at the existing Coggon 161 kV substation. The project comprises 40 Sungrow SG2500U 2500 kW inverters.

IR36 was queued after the MISO DPP 2018 April study cycle. The Interconnection System Impact study was performed using study cases from the MISO DPP 2017 February West study and DPP 2017 August West study with selected Generator Interconnection projects included from the DPP 2017 August and DPP 2018 April study cycles. IR36 will be subject to restudy with all DPP 2017 August and DPP 2018 April study cycle projects after those study cycles are complete.

1.1 Mitigation Summary Table 1-1 shows the estimated cost for network upgrades required to obtain Interconnection Service. Costs are planning level estimates and subject to revision in the facility studies.

Table 1-1. Total Cost of Network Upgrades Excluding Interconnection Facilities

Cost ($)

Network Upgrades, Thermal and Voltage $2,500,000

Network Upgrades, Short Circuit $0

Network Upgrades, Transient Stability $0

Total Transmission Costs $2,500,000


Executive Summary


1-2

1.2 Steady State Contingency Analysis Power flow and contingency analyses were performed to identify and mitigate any thermal or voltage issues caused by the IR36 project. Study cases representing summer peak system conditions and summer shoulder system conditions were created with IR36 dispatched at rated output. System performance was benchmarked using cases without IR36.

Power flow and nonlinear (ac) contingency analyses were performed on the benchmark and study cases, and the incremental impact of the IR36 project was evaluated by comparing the steady-state performance of the transmission system in the benchmark and study cases.

There are two IR36 thermal constraints. The Coggon 161-69 kV transformer will need to be replaced with a 200 MVA unit and the Liberty 161-69 kV transformer will need to be replaced with a 150 MVA unit. Replacement of the Coggon transformer is a required network upgrade for IR36. Replacement of the Liberty transformer is a required network upgrade for IR20; IR36 does not have any cost responsibility for the Liberty transformer unless IR20 is withdrawn from the generator interconnection queue. There are no IR36 steady state voltage constraints.

Table 1-2. Network Upgrades Required for Steady State Analysis

Constraint Owner Mitigation Cost

Liberty 161-69 kV transformer CIPCO Remove existing transformer and replace with 150 MVA unit. $2,500,000 (Note 1)

Coggon 161-69 kV transformer CIPCO Remove existing transformer and replace with 200 MVA unit. $2,500,000

Note 1: IR20 is responsible for replacement of the Liberty transformer.

1.3 Reactive Power Requirements FERC Order 827 requires that large generating facilities comprising non-synchronous generators be designed with a dynamic reactive capability corresponding to a power factor of ±0.95 at the high side of the generator substation.

Reactive power capability of the IR36 project was tested considering a voltage range of 0.95 per unit to 1.05 per unit at the high side of the generator substation. When dispatched at rated output, IR36 is capable of injecting reactive power at 0.95 power factor when the POI voltage is less than 168.2 kV (1.045 per unit) and is capable of absorbing reactive power at 0.95 power factor when the POI voltage is greater than 155.4 kV (0.965 per unit).

IR36 satisfies reactive power requirements.

1.4 Short Circuit Analysis A short circuit analysis was performed to assess the impact of the IR36 generating facility on the adequacy of existing circuit breakers and related equipment in the study area. The analysis was performed using a short circuit database provided by CIPCO.


Executive Summary

1-3


After integrating IR36, the three-phase fault current at the Coggon 161 kV bus is 9,834 amperes, which is an increase of 583 amperes. The single line-to-ground fault current at Coggon is 9,718 amperes, which is an increase of 1,879 amperes.

Fault current is less than 16.8 kA at 161 kV buses near the IR36 POI, less than 16.3 kA at 115 kV buses, and less than 21.5 kA at nearby 69 kV buses.

Transmission owners are reviewing these results to confirm that there are no IR36 short circuit constraints.

1.5 Short Circuit Ratio Inverter-based resources require grid strength to operate reliably. Short circuit ratio is a measure of system strength relative to the rating of the plant and is used by manufacturers to screen for weak grid risks such as fast control stability.

IR36 is electrically close to the IR20 project. The use of short circuit ratio to estimate system strength for an inverter-based resource connected close to other inverter-based resources can lead to overly optimistic results. The Composite Short Circuit Ratio (CSCR) was calculated to estimate the system strength for both projects.

The minimum SCR for P0 and P1 conditions is 5.0, which satisfies the study requirement that the SCR be 3.0 or higher. The minimum SCR for N-2 conditions is 2.5. Coordination between IR20 and IR36 will be required to ensure that both projects are able to operate at an SCR of 2.5; plant output may need to be curtailed to avoid instability for N-2 conditions.

1.6 Voltage Stability Analysis MWEX voltage stability analysis is performed to determine if the system is in a stable state such that a change in system condition does not cause an uncontrollable decline in voltage.

IR36 distribution factors on branches connected to the Arrowhead 230 kV bus were calculated for the worst contingency. The net MW impact is negative, so MWEX voltage stability analysis is not required for IR36.

1.7 Transient Stability Analysis A transient stability analysis was performed to identify and mitigate any transient stability issues caused by the IR36 project. Transient stability analysis was performed for summer shoulder conditions.

Disturbances were simulated to evaluate transient stability. If a simulation for the study case violated transient stability criteria, the simulation was repeated on the benchmark case to assess the impact of IR36 on the violation.

No transient stability constraints were identified for the IR36 project.


Executive Summary


1-4



2-1


Section

2 Introduction The generation project listed in Table 2-1 has requested to interconnect to the CIPCO transmission network.

Table 2-1. CIPCO Interconnection Request IR36

Queue #

Queue Date County POI

Max Output

Requested ISD

Fuel Type Comments

36 12/11/2018 Linn, IA Coggon 161 kV Substation 100 MW 12/31/2020 Solar

IR36 was queued after the MISO DPP 2018 April study cycle. The Interconnection System Impact study was performed using study cases from the MISO DPP 2017 February West study and DPP 2017 August West study with selected Generator Interconnection projects included from the DPP 2017 August and DPP 2018 April study cycles. IR36 will be subject to restudy with all DPP 2017 August and DPP 2018 April study cycle projects after those study cycles are complete.

The Interconnection System Impact Study was performed under the direction of CIPCO by Siemens PTI and an ad hoc study group. The ad hoc study group was formed to review the study scope, methodology, models and results. The ad hoc study group consisted of representatives from the interconnection customer and the following utility companies – Ameren, American Transmission Company, Associated Electric Cooperative, Cedar Falls Utilities, Central Iowa Power Cooperative, City of Ames, Corn Belt Power Cooperative, ITC Midwest, MidAmerican Energy Company, Midcontinent Independent System Operator, Missouri River Energy Services, Muscatine Power & Water, Northeast Missouri Electric Power Cooperative, PJM Interconnection, Southwest Power Pool, Western Area Power Administration.


Introduction


2-2



3-1


Section

3 Steady State Analysis Power flow and contingency analyses were performed to identify and mitigate any thermal or voltage issues caused by the IR36 project.

3.1 Study Methodology Study cases representing summer peak (SPK) system conditions and summer shoulder (SH) system conditions were created with IR36 dispatched at rated output. System performance was benchmarked using cases without IR36.

Power flow and nonlinear (ac) contingency analysis were performed on the benchmark and study cases, and the incremental impact of the IR36 project was evaluated by comparing the steady-state performance of the transmission system in the benchmark and study cases.

Steady-state analyses were performed using PSS®E version 33.12 and PSS®MUST version 12.0.

3.2 Case Development IR36 was queued after the MISO DPP 2018 April study cycle. MISO has completed the DPP 2017 February Phase 3 study and has determined network upgrades required for the 2017 February projects. The DPP 2017 August and DPP 2018 April study cycles have more than 14,000 MW of generation in the MISO west region; it was not feasible to include all prior queued MISO projects in the IR36 study since the associated network upgrades were not known at the time the IR36 study commenced. The approach taken was to model selected projects that have the largest impact on IR36. IR36 will be subject to restudy with all prior queued MISO projects after mitigation has been determined for those study cycles.

Benchmark (pre-IR36) power flow cases representing summer peak and summer shoulder system conditions were created as follows.

1. Start from MISO DPP 2017 August West Phase 1 cases. 2. Remove MISO DPP 2017 February West projects withdrawn after Phase 2. 3. Remove DPP 2017 February West Phase 2 base case upgrades and network

upgrades. 4. Remove DPP 2017 August study projects and network upgrades. 5. Add CIPCO 69 kV detail. 6. Add CIPCO and MPW Line 106 project. 7. Add CIPCO prior queued projects. 8. Add selected MISO projects from 2017 August and 2018 April study cycles.

Prior queued generators are listed in Appendix A. Generation added to the benchmark cases was dispatched consistent with MISO fuel type assumptions shown in Table 3-1. Generation


Steady State Analysis


3-2

in the MISO Classic area was scaled uniformly to accommodate generation changes, and the power flow cases were solved with transformer tap adjustment enabled, area interchange disabled, phase shifter adjustment enabled, and switched shunt adjustment enabled.

Study cases were created from the benchmark cases by adding and dispatching the IR36 project. CIPCO practice is to dispatch the study project at rated output in the summer peak and summer shoulder cases. Generation in the MISO Classic areas was scaled uniformly to accommodate generation changes, and the power flow cases were solved using the same solution options as the benchmark cases.

Table 3-1. MISO Dispatch Assumptions

Fuel Type Summer Peak Summer Shoulder

Diesel 100% 0%

Wind 15.6% 100%

Solar 100% 50%

A diagram showing the IR36 POI is included in Appendix A.

3.3 Contingency Criteria A variety of contingencies were considered for steady-state analysis:

NERC Category P0 with system intact (no contingencies) NERC Category P1 contingencies

o NERC Category P1 contingencies, at buses with a nominal voltage of 69 kV and above, in the following areas: AMIL (area 357), AMMO (area 356), ATC (areas 295, 296, 694, 696, 697, 698), DPC (area 680), ITCM (area 627), MEC (area 635), MPW (area 633), XEL (area 600), AECI (area 330), BEPC-SPP (area 659), CE (area 222), GMO (area 540), INDN (area 545), KACY (area 542), KCPL (area 541), LES (area 650), NPPD (area 640), OPPD (area 645), WAPA (area 652).

o Multiple-element NERC Category P1 contingencies in Illinois, Iowa, Missouri, Minnesota and Wisconsin.

NERC Category P2-P7 contingencies o NERC Category P2, P4, P5, and P7 contingencies in Illinois, Iowa, Missouri, Minnesota

and Wisconsin.

Selected P3, P6, and N-2 contingencies were simulated to screen for thermal and voltage violations on CIPCO facilities. CIPCO N-2 contingency criteria only apply to transmission facilities having a nominal rating of 100 kV or above.



3-3


3.4 Monitored Elements The study area is defined in Table 3-2. Facilities in the study area were monitored for system intact and post-contingency conditions using the limits shown in Table 3-2.

Table 3-2. Monitored Elements

Owner / Area

Monitored Facilities

Thermal Limits 1 Voltage Limits 2

Pre-Disturbance

Post-Disturbance Pre-Disturbance

Post-Disturbance

AECI 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

AMIL 69 kV and above 100% of Rate A 100% of Rate B 1.05/1.0 1.05/0.95

AMMO 69 kV and above 100% of Rate A 100% of Rate B 1.05/1.0 1.05/0.95

ATC 69 kV and above 95% of Rate A 95% of Rate B 1.05/0.95 1.1/0.9

BEPC-SPP 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

CBPC 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

CE 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

DPC 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

GMO 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

INDN 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

ITCM 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.93

KACY 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

KCPL 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

MEC 69 kV and above 100% of Rate A 100% of Rate B 1.07/1.05/0.96/0.95 1.05/0.96/0.95 3

MPW 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.05/0.95

MRES 69 kV and above 100% of Rate A 100% of Rate B 1.07/1.05/0.97 1.1/0.92

NPPD 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

OPPD 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

WAPA 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.1/0.9

XEL 69 kV and above 100% of Rate A 100% of Rate B 1.05/0.95 1.05/0.92

Notes 1: PSS®E Rate A, Rate B or Rate C 2: Limits dependent on nominal bus voltage 3: For Cedar Falls Utilities and Ames Municipal Utilities facilities, post-contingency voltage limits for facilities

> 200 kV are 1.05/0.94, and 1.05/0.93 for others.




3-4

3.5 Performance Criteria 3.5.1 CIPCO CIPCO facilities are evaluated with IR36 dispatched at 100% of rated output in the summer peak and summer shoulder cases. A CIPCO facility is considered a thermal injection constraint if the branch is loaded above its applicable normal or emergency rating for the post-change case, and the generator has a larger than 3% distribution factor (DF) on the overloaded facility under post contingent condition or 5% DF under system intact condition.

A CIPCO bus is considered a voltage constraint if both of the following conditions are met.

1. the bus voltage is outside of applicable normal or emergency limits for the post-change case, and

2. the bus voltage is at least 0.01 per unit worse than the benchmark case voltage for the same contingency.

3.5.2 MISO MISO facilities are evaluated with IR36 dispatched at 100% of rated output in the summer peak case and at 50% in the summer shoulder case. A MISO branch is considered a thermal injection constraint if the branch is loaded above its applicable normal or emergency rating for the post-change case, and any of the following conditions are met:

1. the generator has a larger than 20% DF on the overloaded facility under post contingent condition or 5% DF under system intact condition, or

2. the megawatt impact due to the generator is greater than or equal to 20% of the applicable rating (normal or emergency) of the overloaded facility, or

3. the overloaded facility or the overload-causing contingency is at generator’s outlet.

A MISO bus is considered a voltage constraint if both of the following conditions are met.



3.5.3 SPP SPP facilities are evaluated with IR36 dispatched at 100% of rated output in the summer peak case and at 50% in the summer shoulder case. A SPP facility is considered a thermal injection constraint if the branch is loaded above its applicable normal or emergency rating for the post-change case, and the generator has a larger than 3% distribution factor (DF) on the overloaded facility under system intact or post contingent conditions.

A SPP bus is considered a voltage constraint if all the following conditions are met.


2. the bus voltage is at least 0.02 per unit worse than the benchmark case voltage for the same contingency, and

3. the study project has a larger than 3% distribution factor on the contingent element.



3-5


3.5.4 PJM PJM facilities are evaluated with IR36 dispatched at 100% of rated output in the summer peak case and at 50% in the summer shoulder case. A PJM facility is considered a thermal injection constraint if the branch is loaded above its applicable normal or emergency rating for the post-change case, and the generator has a larger than 5% distribution factor (DF) on the overloaded facility under system intact or post contingent conditions.

A PJM bus is considered a voltage constraint if both of the following conditions are met.



3.5.5 AECI AECI facilities are evaluated with IR36 dispatched at 100% of rated output in the summer peak case and at 50% in the summer shoulder case. An AECI facility is considered a thermal injection constraint if the branch is loaded above its applicable normal or emergency rating for the post-change case, and the megawatt impact due to the generator is greater than or equal to 3% of the applicable rating.

An AECI bus is considered a voltage constraint if both of the following conditions are met.



3.6 Contingency Analysis Results

3.6.1 Summer Peak Summer peak contingency analysis results are shown in Appendix B, Table B-1 through Table B-17.

Table B-17 lists contingencies that do not converge in the summer peak case. These contingencies do not converge in the benchmark case or in the study case. The problems are local in nature and not related to IR36 so no mitigation is required.

3.6.1.1 CIPCO Constraints Details for CIPCO summer peak constraints are listed in Appendix B, Table B-1 through Table B-6. CIPCO thermal constraints are summarized in Table 3-3; there are no CIPCO voltage constraints in the summer peak case.

3.6.1.2 MISO Constraints There are no MISO thermal or voltage constraints in the summer peak case.




3-6

3.6.1.3 SPP Constraints There are no SPP thermal or voltage constraints in the summer peak case.

3.6.1.4 PJM Constraints There are no PJM thermal or voltage constraints in the summer peak case.

3.6.1.5 AECI Constraints There are no AECI thermal or voltage constraints in the summer peak case.

3.6.2 Summer Shoulder Summer shoulder power flow and contingency analysis results are shown in Appendix B, Table B-18 through Table B-34.

Table B-34 lists contingencies that do not converge in the summer shoulder case. These contingencies do not converge in the benchmark case or in the study case. The problems are local in nature and not related to IR36, so no mitigation is required.

3.6.2.1 CIPCO Constraints Details for CIPCO summer shoulder constraints are listed in Appendix B, Table B-18 through Table B-23. CIPCO thermal constraints are summarized in Table 3-4; there are no CIPCO voltage constraints in the summer shoulder case.

3.6.2.2 MISO Constraints There are no MISO thermal or voltage constraints in the summer shoulder case.

3.6.2.3 SPP Constraints There are no SPP thermal or voltage constraints in the summer shoulder case.

3.6.2.4 PJM Constraints There are no PJM thermal or voltage constraints in the summer shoulder case.

3.6.2.5 AECI Constraints There are no AECI thermal or voltage constraints in the summer shoulder case.

3.7 Network Upgrades Network upgrades required to mitigate IR36 thermal constraints are shown in Table 3-5. Replacement of the Coggon transformer is a required network upgrade for IR36. Replacement of the Liberty transformer is a required network upgrade for IR20; IR36 does not have any cost responsibility for the Liberty transformer unless IR20 is withdrawn from the generator interconnection queue. There are no steady state voltage constraints.

Costs are planning level estimates and subject to revision in the facility studies.



3-7


Table 3-3. CIPCO SUM Thermal Constraints, Maximum Screened Loading

Benchmark Case

Pre-GI Loading

Study Case

Post-GI Loading

Monitored Element Owner Rating MVA % MVA % Contingency Type

629208 COGGON J8 69.0 631209 COGGON 5 161 1

CIPCO 100 16.5 16.5 107.1 107.1 DUNDEE 5 161 - IR-20 POI 161 1 COFFEY5 161 - COGGON 5 161 1

N-2

Table 3-4. CIPCO SSH Thermal Constraints, Maximum Screened Loading

Benchmark Case

Pre-GI Loading

Study Case

Post-GI Loading

Monitored Element Owner Rating MVA % MVA % Contingency Type

630019 LIBERTY8 69.0 631100 LIBERTY5 161 1

CIPCO 84 101.5 120.9 107.2 127.6 P7:161-345:ITCM:LIBERTY5-HCKRYCK5 HAZLETON3-HCKRYCK3:IA-NE LIBERTY5 161 - HCKRYCK5 161 1 HCKRYCK3 345 - HAZLTON3 345 1

P1-P7

630019 LIBERTY8 69.0 631100 LIBERTY5 161 1

CIPCO 84 101.5 120.9 107.2 127.6 LIBERTY5 161 - HCKRYCK5 161 1 HAZLTON3 345 - HCKRYCK3 345 1

N-2

629208 COGGON J8 69.0 631209 COGGON 5 161 1

CIPCO 100 52.8 52.8 152.6 152.6 DUNDEE 5 161 - IR-20 POI 161 1 COFFEY5 161 - COGGON 5 161 1

N-2




3-8

Table 3-5. Network Upgrades Study Case

Post-GI Loading

Monitored Element Owner Rating MVA % Type Mitigation Cost

630019 LIBERTY8 69.0 631100 LIBERTY5 161 1

CIPCO 84 107.2 127.6 P1-P7 Remove existing transformer and replace with 150 MVA unit. $2,500,000 (Note 1)

629208 COGGON J8 69.0 631209 COGGON 5 161 1

CIPCO 100 152.6 152.6 N-2 Remove existing transformer and replace with 200 MVA unit. $2,500,000

Note 1: IR20 is responsible for replacement of the Liberty transformer.



3-9


3.8 Reactive Power Requirements FERC Order 827 requires that large generating facilities comprising non-synchronous generators be designed with a dynamic reactive capability corresponding to a power factor of ±0.95 at the high side of the generator substation.

Voltage control is typically implemented using droop control as shown in Figure 3-1. The reactive power analysis assumes that IR36 is set to regulate the POI voltage at 164 kV with a 3 kV voltage droop setting. This means that when the POI voltage is 161 kV (1.00 per unit) the system will regulate reactive flow to achieve a power factor of 0.95 capacitive whereas when the POI voltage is 167 kV (1.037 per unit) the system will regulate reactive flow to achieve a power factor of 0.95 inductive.

Figure 3-1. Control Logic for the Voltage Set-point Signal

3.8.1 Methodology With IR36 dispatched at rated power output, the ability of the project to absorb and inject reactive power at the POI was calculated while varying the POI voltage from 1.05 per unit to 0.95 per unit.

Solar inverter capability was modeled based on manufacturer data1. Table 3-6 summarizes the reactive power limits as a function of terminal voltage (valid at ambient temperatures up to 45 ºC).

AC voltage range: 550 V ±10% Maximum AC apparent power: 1.0 per unit (2750 kVA) Reactive power limits: ±0.378 per unit (±1039.5 kvar) Maximum AC output current: 1.0 per unit

1 Voltage range, maximum apparent power and maximum output current from DS_SG2500U_Datasheet_V10_EN_20170627.pdf. Reactive power limits from dynamics model.




3-10

Table 3-6. Inverter Reactive Power Limits, Pgen = 100 MW

Voltage Reactive Power Limits

(Mvar)

0.90 pu Power Curtailed

0.91 pu ± 4.5 Mvar

0.95 pu ±30.3 Mvar

≥ 1.00 pu ± 41.6 Mvar

Reactive power capability was determined based on the assumed transformer tap settings shown in Table 3-7. The case includes a 14 Mvar capacitor connected at the 34.5 kV collector bus. The reactive power analysis assumes that the 34.5 kV collector system is designed such that the inverters can utilize the full operating range from 90% to 110% of nominal voltage.

Table 3-7. Assumed Transformer Tap Settings Description Tap setting

Main Power Transformer 1.000

Equivalent GSU Transformer 1.025

3.8.2 Results Figure 3-2 shows the reactive power capability curve for the IR36 project. The unshaded area represents the operating range. IR36 is capable of injecting reactive power at 0.95 power factor when the POI voltage is less than 1.045 per unit (168.2 kV). This satisfies reactive power requirements because the project can inject reactive power along the controller droop setting (blue line) for voltage between 0.95 and 1.0 per unit (150 kV to 161 kV).

IR36 is capable of absorbing reactive power at 0.95 power factor when the POI voltage is greater than 0.965 per unit (155.4 kV). This satisfies reactive power requirements because the project can absorb reactive power along the controller droop setting (blue line) when voltage is greater than 1.037 per unit (167 kV).



3-11


Figure 3-2. Power Factor Capability Versus POI Voltage




3-12



4-1


Section

4 Short Circuit Analysis Short circuit analysis is performed to assess the impact of the IR36 generating facility on the adequacy of existing circuit breakers and related equipment in the study area.

4.1 Methodology Short circuit analysis was performed using CAPE version 14.0. A short circuit database provided by CIPCO was used to benchmark system performance without IR36. A study case was created representing system conditions with IR36. Three-phase and single-line-to-ground faults were simulated at buses near the IR36 POI, and the incremental impact of the IR36 project was calculated by comparing currents in the benchmark and study cases.

4.2 Short Circuit Database A benchmark (pre-IR36) short circuit database was created as follows.

Start from database “ITCMW_MASTER.fdb” that was used for the IR24, IR27, IR30, IR32, IR34 Group study.

Add IR20; 50 MW wind at new substation on Coggon-Dundee 161 kV. Increase Liberty 161-69 transformer to 150 MVA (IR20 NU); copied Wellsburg 161-69

transformer. Add J959; DPP 2018 APR; 150 MW at Windsor 161kV Substation. Add J963; DPP 2018 APR; 10.2 MW diesel at Bennet-Graham 69 kV line tap. Add J999; DPP 2018 APR; 100 MW solar at Fairfax 161kV Substation.

The IR36 short circuit study model was developed from the benchmark database as follows.

Add IR36 project using model data shown in Appendix A.5. Increase Coggon 161-69 transformer to 200 MVA (IR36 NU); copied Beverly 161-69

transformer.

4.3 Short Circuit Analysis Results Short circuit analysis was performed on the study case (with the IR36 project) and benchmark case (without the IR36 project). The following classical short circuit solution options were used in the short circuit analysis calculations:

Prefault voltage was set to “1.00 per unit with multiplier of 1” All loads, shunts and transformer magnetizing branches were ignored.

Short circuit currents were calculated at substations within ten buses of the IR36 POI. Short circuit currents at buses where the change in fault current exceeds 1% are listed in Table 4-1.


Short Circuit Analysis


4-2

After integrating IR36, the three-phase fault current at the Coggon 161 kV bus is 9,834 amperes, which is an increase of 583 amperes. The single line-to-ground fault current at Coggon is 9,718 amperes, which is an increase of 1,879 amperes.

Fault current is less than 16.8 kA at 161 kV buses near the IR36 POI, less than 16.3 kA at 115 kV buses, and less than 21.5 kA at nearby 69 kV buses.

Transmission owners are reviewing these results to confirm that there are no IR36 short circuit constraints.



4-3


Table 4-1. Fault Current Comparison

SLG Fault Current Comparison 3PH Fault Current Comparison

Substation Bus kV Owner Benchmark

Case (A) Study

Case (A) Difference

(A) Difference

(%) Benchmark

Case (A) Study

Case (A) Difference

(A) Difference

(%)

IR36SUB 800158 IR36SUB 161 CIPCO - 9685.7 - - - 9809.3 - -

COGGON 629208 COGGON 69 J1 69 CIPCO 8697.2 13841.5 5144.3 59% 8885.2 12549.8 3664.6 41%

COGGON 391 COGGON 69 J2 69 CIPCO 8697.2 13841.5 5144.3 59% 8885.2 12549.8 3664.6 41%

COGGON 631209 COGGON 161 161 CIPCO 7838.6 9717.8 1879.2 24% 9250.6 9833.8 583.2 6%

IR20 13103 IR20SUB 161 CIPCO 7960.5 8645.5 685.0 9% 9404.3 9780.7 376.4 4%

COFFEY 631147 COFFEY_L1 161 ITCM 9769.7 10460.7 691.0 7% 11173.9 11491.9 318.0 3%




RADIO 630747 RADIO J1 69 ITCM 6020.1 6088.5 68.4 1% 9344.5 9578.0 233.5 2%

SANDSPRINGS 630493 SANDSPN 69 69 ITCM 5582.7 5680.1 97.4 2% 6248.7 6401.3 152.6 2%

DUNDEE 631101 DUNDEE 161 161 CIPCO 9233.7 9568.2 334.5 4% 11183.2 11448.7 265.5 2%

COFFEY 631146 COFFEY_K1 115 ITCM 10702.8 10903.9 201.1 2% 10813.2 11040.7 227.5 2%

HIAWATHA 630017 HIAWATHA J1 69 ITCM 21317.7 21403.2 85.5 0% 20605.8 20951.7 345.9 2%

HIAWATHA 630760 HIAWATHA J2 69 ITCM 21317.7 21403.2 85.5 0% 20605.8 20951.7 345.9 2%

HIAWATHA 313 HIA DIST TAP 69 ITCM 20567.1 20645.5 78.4 0% 20309.8 20648.6 338.8 2%

MONTICELLO INDUSTRIAL

630843 MONT IND J1 69 Alliant 4122.2 4166.2 44.0 1% 5166.5 5251.4 84.9 2%


900363 MONT IND J2 69 Alliant 4122.2 4166.2 44.0 1% 5166.5 5251.4 84.9 2%


1872 MONT J1 FUT 69 Alliant 4122.2 4166.2 44.0 1% 5166.5 5251.4 84.9 2%

SWAMPFOX 631027 SWMPFOX115K1 115 Alliant 9124.2 9181.1 56.9 1% 10990.1 11168.3 178.2 2%




4-4

SLG Fault Current Comparison 3PH Fault Current Comparison

Substation Bus kV Owner Benchmark

Case (A) Study

Case (A) Difference

(A) Difference

(%) Benchmark

Case (A) Study

Case (A) Difference

(A) Difference

(%)

SWAMPFOX 900054 SWMPFOX115K2 115 Alliant 9124.2 9181.1 56.9 1% 10990.1 11168.3 178.2 2%

MARION 1172 MARION 69J1 69 ITCM 17411.5 17472.6 61.1 0% 18174.6 18460.1 285.5 2%

MARION 630759 MARION 69J2 69 ITCM 17411.5 17472.6 61.1 0% 18174.6 18460.1 285.5 2%

HIAWATHA 11 Hiawatha Cap 161 ITCM 15914.0 16214.7 300.7 2% 16513.5 16746.5 233.0 1%

HIAWATHA 631089 HIAWATHA L1 161 ITCM 15914.0 16214.7 300.7 2% 16513.5 16746.5 233.0 1%





MARION 631019 MARION 115K1 115 ITCM 13152.4 13195.3 42.9 0% 15562.8 15763.9 201.1 1%

MARION 631195 MARION 115K2 115 ITCM 13152.4 13195.3 42.9 0% 15562.8 15763.9 201.1 1%

OLDSETTLERS 631167 OLD SETTL K1 115 ITCM 12129.8 12162.3 32.5 0% 14689.4 14876.7 187.3 1%

OLDSETTLERS 900404 OLD SETTL K2 115 ITCM 12129.8 12162.3 32.5 0% 14689.4 14876.7 187.3 1%

EMERALDISLE 629380 Emerald I J1 69 ITCM 13074.6 13102.5 27.9 0% 16385.6 16591.0 205.4 1%

EMERALDISLE 900353 Emerald I J2 69 ITCM 13074.6 13102.5 27.9 0% 16385.6 16591.0 205.4 1%

DRYCREEK 631031 DRYCRK115K1 115 ITCM 12299.3 12324.4 25.1 0% 14443.8 14623.2 179.4 1%

DRYCREEK 90055 DRYCRK115K2 115 ITCM 12299.3 12324.4 25.1 0% 14443.8 14623.2 179.4 1%

HIAWATHA 631018 HIAWATHA 115 115 ITCM 16248.9 16282.2 33.3 0% 16024.1 16218.7 194.6 1%

COLLINSNW69CR 629185 COLLINS J1 69 ITCM 10630.6 10652.4 21.8 0% 13743.0 13906.2 163.2 1%

COLLINSNW69CR 1171 COLLINS J2 69 ITCM 10630.6 10652.4 21.8 0% 13743.0 13906.2 163.2 1%



4-5


4.4 Short Circuit Ratio Inverter-based resources require grid strength to operate reliably. Short circuit ratio is a measure of system strength relative to the rating of the plant and is used by manufacturers to screen for weak grid risks such as fast control stability.

IR36 is electrically close to the IR20 project. The use of short circuit ratio to estimate system strength for an inverter-based resource connected close to other inverter-based resources can lead to overly optimistic results. The composite short circuit ratio (CSCR) estimates the equivalent system impedance seen by multiple inverter-based resources and is calculated as

CSCR = Composite SC MVA

∑ converter MW rating

To calculate CSCR, a common 34.5 kV bus is created by tying together the IR36 and IR20 collector buses. The Composite Short Circuit MVA is the 3-phase short circuit MVA at the common bus excluding any contribution from IR36 or IR20.

The CSCR was calculated after replacing the Liberty 161-69 transformer and Coggon 161-69 transformer as noted in 4.2. The CSCR for system intact and selected post-contingent conditions is shown in Appendix C, Table C-1. The lowest CSCRs for P0 system intact conditions, P1 post-contingent conditions, and N-2 post-contingent conditions are shown in Table 4-2.

The minimum SCR for P0 and P1 conditions is 5.0, which satisfies the study requirement that the SCR be 3.0 or higher. The minimum SCR for N-2 conditions is 2.5. Coordination between IR20 and IR36 will be required to ensure that both projects are able to operate at an SCR of 2.5; plant output may need to be curtailed to avoid instability for N-2 conditions.

Table 4-2. IR20/IR36 Composite Short Circuit Ratio

System Intact or Post-Contingent Condition Type CSCR

System Intact P0 6.4

IR20-Dundee 161 kV line P1 5.0

Coggon-Coffey 161 kV line IR20-Dundee 161 kV line

N-2 2.5




4-6



5-1


Section

5 Voltage Stability Analysis MWEX voltage stability analysis is performed to determine if the system is in a stable state such that a change in system condition does not cause an uncontrollable decline in voltage.

IR36 distribution factors on branches connected to the Arrowhead 230 kV bus were calculated for the worst contingency. The net MW impact is the sum of the MW impacts on all branches connected to the bus. The results in Table 5-1 show that the net impact is negative, so MWEX voltage stability analysis is not required for IR36.

Table 5-1. IR36 MW Impact on Arrowhead 230 kV Bus

Monitored Branch Flow 1 OTDF MW Impact

Arrowhead – Arrowhead DC P1 230 -186.8 0.00% 0.00

Arrowhead – Arrowhead DC P2 230 -186.8 0.00% 0.00

Arrowhead – 98L Tap 230 -150.0 0.37% -0.37

Arrowhead – Forbes 230 -160.6 0.14% -0.14

Arrowhead – Bear Creek 230 16.2 -0.35% -0.35

Arrowhead – Arrowhead PST 230 446.9 -0.46% -0.46

Arrowhead 230/115 #1 107.5 0.14% 0.14

Arrowhead 230/115 #2 111.3 0.15% 0.15

Net MW Impact -1.03 MW

Note 1. Flow < 0 indicates flow direction is from the remote end toward the Arrowhead substation.


Voltage Stability Analysis


5-2



6-1


Section

6 Transient Stability Analysis Transient stability analysis is performed to determine if the system is in a stable state such that synchronism is maintained when subjected to a severe disturbance.

6.1.1 Study Methodology A study case representing summer shoulder (SH) system conditions was created with IR36 dispatched at rated output. System performance was benchmarked using cases without IR36. The cases were created from the MISO DPP 2017 February West Phase 3 stability package using the process outlined in Section 6.1.2.

Disturbances were simulated to evaluate transient stability. If a simulation for the study case violated transient stability criteria, the simulation was repeated on the benchmark case to assess the impact of IR36 on the violation.

6.1.2 Case Development A benchmark (pre-IR36) power flow case representing summer shoulder system conditions was created as follows.

Start from MISO DPP 2017 February West Phase 3 stability package. Add CIPCO 69 kV detail. Add CIPCO and MPW Line 106 project. Add CIPCO prior queued projects. Increase Liberty 161-69 transformer to 150 MVA (IR20 NU); copied Wellsburg 161-69

kV transformer. Add selected MISO projects from 2017 August and 2018 April study cycles.

Prior queued generators are listed in Appendix A. Generation added to the benchmark cases was dispatched consistent with MISO fuel type assumptions shown in Table 3-1 and generation in the MISO Classic area was scaled uniformly to accommodate generation changes.

Study cases were created from the benchmark cases as follows.

Add and dispatch the IR36 project. Increase the Coggon 161-69 kV transformer to 200 MVA (IR36 NU); copied Beverly

161-69 transformer.

IR36 is modeled using a generic renewable generator dynamic stability model with model parameters provided by the IC that are representative of the IR36 solar inverters and Power Plant Controller. IR36 power flow and dynamics data are listed in Appendix A.


Transient Stability Analysis


6-2

6.1.3 Contingency Criteria The stability simulations performed as part of this study considered the contingencies listed in Table 6-1. Switching sequences were developed based on generic clearing times. Admittances used to simulate single line-to-ground (SLG) faults were estimated assuming that the Thevenin impedance of the positive, negative and zero sequence networks at the fault point are equal.

Table 6-1. Disturbance Descriptions

Disturbance Name Description NERC Cat. Area

P0 No disturbance P0

P12_Coggon_IR20_161 3PH fault on Coggon to IR20 161 kV line; cleared at 6 cycles. P12 IR36

P12_Coggon_Coffey_161 3PH fault on Coggon to Coffey 161 kV line; cleared at 6 cycles. P12 IR36

P12_IR20_Dundee_161 3PH fault on IR-20 POI to Dundee 161 kV line; cleared at 6 cycles. P12 IR36

P12_Coffey_Hiawatha_161 3PH fault on Coffey to Hiawatha 161 kV line; cleared at 6 cycles. P12 IR36

P12_Dundee_Hazleton_161 3PH fault on Dundee to Hazleton 161 kV line; cleared at 6 cycles. P12 IR36

P42_Coggon_IR20_161 SLG fault on Coggon to IR20 161 kV line; breaker fails at Coggon; cleared at 18 cycles by tripping Coggon 161-69 kV xfmr.

P42 IR36

P42_Coggon_Coffey_161 SLG fault on Coggon to Coffey 161 kV line; breaker fails at Coggon; cleared at 18 cycles by tripping Coggon 161-69 kV xfmr.

P42 IR36

P42_Dundee_Liberty_161 SLG fault on Dundee to Liberty 161 kV line; breaker fails at Dundee; cleared at 18 cycles by disconnecting Dundee 161 kV bus.

P42 IR36

P42_Hiawatha_Arnold_161 SLG fault on Hiawatha to Arnold 161 kV line; breaker fails at Hiawatha; cleared at 18 cycles by tripping Hiawatha capacitor.

P42 IR36

P611_Coggon-Coffey_Coggon-IR20_161

Prior outage of Coggon-Coffey 161. 3PH fault on Coggon-IR-20 161 kV line; cleared at 6 cycles.

P611 IR36

P611_IR20-Dundee_Coggon-Coffey_161

Prior outage of IR20-Dundee 161. 3PH fault on Coggon to Coffey 161 kV line; cleared at 6 cycles.

P611 IR36

P611_IR20-Dundee_Coffey-Hiawatha_161

Prior outage of IR20-Dundee 161. 3PH fault on Coffey-Hiawatha 161 kV line; cleared at 6 cycles.

P611 IR36

6.1.4 Performance Criteria

6.1.4.1 Default Criteria Stability simulation results were evaluated based on the following criteria:

All on-line generating units are stable No unexpected generator tripping Default transient voltage limits

– High voltage: 1.2 per unit – Low voltage: 0.7 per unit from 0 to 20 seconds after fault clearing



6-3


Transient voltage limits given in Transmission Owner planning criteria are utilized when different from the default limits given above.

Angular transient stability minimum damping ratio (ζ) should not be less than 0.03.

A bus is considered a transient voltage constraint if both of the following conditions are met. All transient voltage constraints must be resolved before a project can receive interconnection service.

The bus transient voltage is outside of specified transient voltage limits during transient period, and

the bus voltage is at least 0.01 per unit worse than the benchmark case voltage for the same contingency.

6.1.4.2 ITCM Local Planning Criteria Facilities in the ITCM footprint were evaluated based on ITCM local planning criteria.

Voltages at all buses on the Transmission Systems should not drop below 0.70 per unit after the first swing for more than 20 cycles. The duration for the minimum voltage dip starts after the first swing post clearing of fault.

Voltage at all Transmission System buses should recover to the applicable post-contingency steady-state voltage level (ITCM post-disturbance limits in Section 3.4), within 6.0 seconds of the clearing of the fault.

Rotor angle oscillation damping ratios are not to be less than 0.03.

6.1.4.3 MEC Local Planning Criteria Facilities in the MEC footprint were evaluated based on MEC local planning criteria.

Generator bus transient voltage limits shall adhere to the high voltage duration and low voltage duration curve in Attachment 2 of NERC PRC-024, which is: – Generator bus transient over voltage limits (after fault clearing): 1.2 pu voltage

from 0.0 to and including 0.2 seconds; 1.175 pu voltage from 0.2 to and including 0.5 seconds; 1.15 pu voltage from 0.5 to and including 1.0 second; 1.1 pu voltage for greater than 1.0 second.

– Generator bus transient low voltage limits (after fault clearing): may be less than 0.45 pu voltage from 0 to 0.15 seconds; Voltage shall remain above 0.45 pu from 0.15 to 0.3 seconds; Voltage shall remain above 0.65 pu from 0.3 to 2.0 seconds; Voltage shall remain above 0.75 pu from 2.0 to 3.0 seconds; Voltage shall recover to 0.9 pu after 3 seconds.

Load bus transient voltage limits: – Load bus transient over voltage limits (after fault clearing): 1.6 pu voltage from

0.01 to and including 0.04 seconds; 1.2 pu voltage from 0.04 to and including 0.5 seconds; 1.1 pu voltage from 0.5 to and including 5 seconds; and 1.05 pu voltage for greater than 5 seconds. These voltage limits also apply to buses without loads or generators.




6-4

– Load bus transient low voltage limits (after fault clearing): may be less than 0.7 pu

voltage from 0 to 2 seconds; Voltage shall remain above 0.7 pu from 2 to 20 seconds; Voltage shall recover to 0.9 pu after 20 seconds.

Angular transient stability minimum damping ratio (ζ) should not be less than 0.03.

6.1.4.4 MPW Local Planning Criteria Facilities in the MPW footprint were evaluated based on MPW local planning criteria, which uses the default criteria described in Section 6.1.4.1.

6.2 Transient Stability Results Transient stability results are summarized in Appendix D. Simulations were performed with a 2.0 second steady-state run followed by the disturbance. Simulations were run for a 12-second duration.

IR36 frequency control was disabled when simulating three-phase faults at Coggon. When voltage at Coggon is driven to zero by a three-phase fault, the IR36 REGC model does not converge until the fault is cleared, causing a spurious output from the REPC frequency deadband and a corresponding drop in inverter output. IR36 frequency control was disabled when simulating three-phase faults at Coggon to avoid an unrealistic reduction in inverter output following fault clearing. These disturbances do not cause a frequency change that would require frequency response.

No system performance issues were identified in the transient stability analysis. There are no IR36 transient stability constraints.


A-1


Appendix

A Case Development A.1 Prior Queued CIPCO Projects Power flow cases include the prior queued projects listed in Table A-1.

Table A-1. Projects from CIPCO GI Queue

Project Num State County Point of Interconnection

Max Output

Fuel Type

20 IA Delaware Coggon‐Dundee 161 kV Line 54 Wind

21 IA Audubon Anita-Guthrie 161 kV line 103.5 Wind

23 IA Union Summit Lake 69 kV 60 Gas

24 IA Adams New 69kV Interconnection Substation near Prescott REC 56 Wind

30 IA Jasper Richland REC 69kV Substation 56 Wind

32 IA Clarke Murray Junction 69kV Substation 56 Wind

34 IA Story Cambridge REC 69kV Substation 48 Wind

35 IA Louisa Newport 161 kV substation 100 Solar

A.2 Network Upgrades for Prior Queued CIPCO Projects Power flow cases include the network upgrades listed in Table A-2.

Table A-2. Network Upgrades Associated with CIPCO GI Queue

Constraint Project Transmission Owner

Liberty 161-69 kV transformer IR20 CIPCO

Guthrie Center 161-69 kV xfmr IR21 CIPCO


Case Development


A-2

A.3 Prior Queued MISO Projects Power flow cases include the prior queued projects listed in the tables below.

Table A-3. DPP 2018 April West and Central Area Projects Note 1

Project Num State County

Transmission Owner Point Of Interconnection

Max Output

Fuel Type

Service Type

J959 IA Fayette SMMPA Windsor 161kV Substation 150 Wind NRIS

J963 IA Cedar ITCM Bennett - Graham 69 kV Line Tap 10.2 Diesel NRIS

J999 IA Linn ITCM Beverly 161kV Substation 100 Solar NRIS

J1181 IA Chickasaw ITCM Hazleton - Mitchell County 345 kV 200 Wind NRIS

Note 1: List represents selected projects from the 2018 April study cycle.


Case Development

A-3


A.4 IR36 Power Flow Data DATA FOR BUS 800155 [IR36 GEN 0.5500] RESIDING IN AREA 627, ZONE 665, OWNER 627: CODE P Q - L O A D I - L O A D Y - L O A D G-SHUNT B-SHUNT 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 X--------- REMOTE BUS ----------X PLNT PGEN QGEN QMAX QMIN VSCHED PCT Q BUS# X-- NAME --X BASKV VOLTAGE 100.0 1.5 41.6 -41.6 1.01900 100.00 631209 COGGON 5 161.00 1.01900 ID ST PGEN QGEN QMAX QMIN MBASE Z S O R C E X T R A N GENTAP PMAX PMIN WMOD 1 1 100.0 1.5 41.6 -41.6 110.0 0.0000******* 0.0000 0.0000 1.0000 100.0 100.0 1 X------- TO BUS --------X XFRMER S W M C C SPECIFIED BUS# X-- NAME --X BASKV CKT X-- NAME --X T 1 T Z M R 1-2 X 1-2 SBAS1-2 800156 IR36 PAD 34.500 1 1 T T 2 1 0.00800 0.05946 100.0 X------- TO BUS --------X C BUS# X-- NAME --X BASKV CKT W WINDV1 NOMV1 ANGLE WINDV2 NOMV2 RATEA RATEB RATEC 800156 IR36 PAD 34.500 1 1 1.00000 0.0000 0.0 1.00000 0.0000 112.0 112.0 0.0 X------- TO BUS --------X W C BUS# X-- NAME --X BASKV CKT 1 W CN RMAX RMIN VMAX VMIN NTPS 800156 IR36 PAD 34.500 1 T 1 0 1.05000 0.95000 1.10000 0.90000 5 DATA FOR BUS 800156 [IR36 PAD 34.500] RESIDING IN AREA 627, ZONE 665, OWNER 627: CODE P Q - L O A D I - L O A D Y - L O A D G-SHUNT B-SHUNT 1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 X------- TO BUS --------X BUS# X-- NAME --X BASKV CKT LINE R LINE X CHARGING ST MET RATE-A RATE-B RATE-C LENGTH 800157 IR36 COL 34.500 1 0.00363 0.00409 0.01295 1 T 0.0 0.0 0.0 0.0 X------- TO BUS --------X XFRMER S W M C C SPECIFIED BUS# X-- NAME --X BASKV CKT X-- NAME --X T 1 T Z M R 1-2 X 1-2 SBAS1-2 800155 IR36 GEN 0.5500 1 1 F F 2 1 0.00800 0.05946 100.0 X------- TO BUS --------X C BUS# X-- NAME --X BASKV CKT W WINDV1 NOMV1 ANGLE WINDV2 NOMV2 RATEA RATEB RATEC 800155 IR36 GEN 0.5500 1 1 1.00000 0.0000 0.0 1.00000 0.0000 112.0 112.0 0.0 X------- TO BUS --------X W C BUS# X-- NAME --X BASKV CKT 1 W CN RMAX RMIN VMAX VMIN NTPS 800155 IR36 GEN 0.5500 1 F 1 0 1.05000 0.95000 1.10000 0.90000 5 DATA FOR BUS 800157 [IR36 COL 34.500] RESIDING IN AREA 627, ZONE 665, OWNER 627: CODE P Q - L O A D I - L O A D Y - L O A D G-SHUNT B-SHUNT 1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 S ADJ X----- REMOTE BUS ------X MOD T METH VHI VLO SHUNT X-------X X-------X X-------X X-------X PCT Q BUS# X-- NAME --X BASKV 3 1 1 0.60000 0.40000 7.00 2: 7.00 100.00 800155 IR36 GEN 0.5500 X------- TO BUS --------X BUS# X-- NAME --X BASKV CKT LINE R LINE X CHARGING ST MET RATE-A RATE-B RATE-C LENGTH 800156 IR36 PAD 34.500 1 0.00363 0.00409 0.01295 1 F 0.0 0.0 0.0 0.0 X------- TO BUS --------X XFRMER S W M C C SPECIFIED BUS# X-- NAME --X BASKV CKT X-- NAME --X T 1 T Z M R 1-2 X 1-2 SBAS1-2 800158 IR36 SUB 161.00 1 1 T T 2 1 0.00264 0.08996 66.0 X------- TO BUS --------X C BUS# X-- NAME --X BASKV CKT W WINDV1 NOMV1 ANGLE WINDV2 NOMV2 RATEA RATEB RATEC 800158 IR36 SUB 161.00 1 1 1.02500 0.0000 0.0 1.00000 0.0000 110.0 110.0 0.0 X------- TO BUS --------X W C BUS# X-- NAME --X BASKV CKT 1 W CN RMAX RMIN VMAX VMIN NTPS 800158 IR36 SUB 161.00 1 T 1 0 1.05000 0.95000 1.10000 0.90000 5 DATA FOR BUS 800158 [IR36 SUB 161.00] RESIDING IN AREA 627, ZONE 665, OWNER 627: CODE P Q - L O A D I - L O A D Y - L O A D G-SHUNT B-SHUNT 1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 X------- TO BUS --------X BUS# X-- NAME --X BASKV CKT LINE R LINE X CHARGING ST MET RATE-A RATE-B RATE-C LENGTH 631209 COGGON 5 161.00 1 0.00000 0.00010 0.00000 1 T 0.0 0.0 0.0 0.0 X------- TO BUS --------X XFRMER S W M C C SPECIFIED BUS# X-- NAME --X BASKV CKT X-- NAME --X T 1 T Z M R 1-2 X 1-2 SBAS1-2 800157 IR36 COL 34.500 1 1 F F 2 1 0.00264 0.08996 66.0 X------- TO BUS --------X C BUS# X-- NAME --X BASKV CKT W WINDV1 NOMV1 ANGLE WINDV2 NOMV2 RATEA RATEB RATEC 800157 IR36 COL 34.500 1 1 1.02500 0.0000 0.0 1.00000 0.0000 110.0 110.0 0.0 X------- TO BUS --------X W C BUS# X-- NAME --X BASKV CKT 1 W CN RMAX RMIN VMAX VMIN NTPS 800157 IR36 COL 34.500 1 F 1 0 1.05000 0.95000 1.10000 0.90000 5


Case Development


A-4

A.5 IR36 Short Circuit Data 2.5 MW inverters modeled as a current-limited source. The current limit is 3,174.6

amperes per inverter, which is 110% of the inverter maximum current of 2886 amperes.

0.55-34.5 kV transformers (YG-D) – kVA base: 2500 – Impedance: Z=6.0%, X/R is 7.375

34.5 kV collector system (100 MVA base) – Zpos: 0.003630+j0.004092 per unit – Zzero: 0.01886+j0.01409 per unit

161 kV GenTie to the POI (100 MVA) – Zpos: X1=0.0001043 per unit – Zzero: X0=0.000338 per unit

161-34.5-13.2 kV 66/88/110 MVA main power transformer (YG-YG-D) – Data shown in Table A-4.

Table A-4. Impedance Data for 161-34.5-13.2 kV Transformer (66 MVA base)

Impedance Winding Z X/R

Positive sequence H-X 9% 34.1

H-Y 12.6% 34.1

X-Y 2.7% 34.1

Zero sequence H-X 9% 34.1

H-Y 12.6% 34.1

X-Y 2.7% 34.1


Case Development

A-5


A.6 IR36 Dynamics Data WIND MODELS REPORT FOR ALL MODELS BUS 800155 [IR36 GEN 0.5500] MODELS Model REGCAU1 Bus 800155 [IR36 GEN 0.5500] Machine "1 " : Tg Rrpwr Brkpt Zerox Lvpl1 0.0200 10.0000 0.9000 0.5000 1.1000 Volim Lvpnt1 Lvpnt0 Iolim 1.2000 0.9000 0.0300 -1.0000 Tfltr Khv Iqrmax Iqrmin Accel 0.0100 0.7000 99.0000 -99.0000 0.7000 LVPL Switch flag: 1 Model REECBU1 Bus 800155 [IR36 GEN 0.5500] Machine "1 " : Vdip Vup Trv dbd1 dbd2 Kqv Iqhl 0.9000 1.1500 0.0167 -0.1000 0.1000 2.0000 1.0000 Iqll Vref0 Tp QMAX -1.0000 1.0000 0.0167 0.3780 QMIN VMAX VMIN Kqp Kqi Kvp Kvi -0.3780 1.1500 0.8000 1.0000 5.0000 0.1000 0.0100 Tiq dPMax dPMin Pmax Pmin 0.0167 99.0000 -99.0000 1.0000 0.0000 Imax Tpord 1.0000 0.0250 PfFLAG: 0 VFLAG: 1 QFLAG: 1 PQFLAG: 0 Model REPCAU1 Bus 800155 [IR36 GEN 0.5500] Machine "1 " : Tfltr Kp Ki Tft Tfv Vfrz Rc 0.0200 18.0000 5.0000 0.0000 0.1500 0.0000 0.0000 Xc Kc emax emin dbd1 dbd2 QMAX 0.0000 0.0400 0.1000 -0.1000 0.0000 0.0000 0.3780 QMIN Kpg Kig tp fdbd1 fdbd2 femax -0.3780 0.1000 0.5000 0.2500 0.0000 0.0000 99.0000 femin Pmax Pmin Tg Ddn Dup -99.0000 1.0000 0.0000 0.1000 20.0000 0.0000 Bus Number for Voltage Control (if 0 local control): 800158 Branch FROM bus number: 0 Branch TO bus number: 0 Branch circuit ID: 0 VCFlag: 0 RefFlag: 1 Fflag: 1


Case Development


A-6

Model VTGTPAT Model Instance 80015501: VL VU PICKUP TB -1.000 1.200 0.060 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015502: VL VU PICKUP TB -1.000 1.175 0.210 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015503: VL VU PICKUP TB -1.000 1.150 0.510 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015504: VL VU PICKUP TB -1.000 1.100 1.010 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015505: VL VU PICKUP TB 0.440 5.000 0.160 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015506: VL VU PICKUP TB 0.640 5.000 0.310 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015507: VL VU PICKUP TB 0.740 5.000 2.010 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model VTGTPAT Model Instance 80015508: VL VU PICKUP TB 0.890 5.000 3.010 0.000 BUS AT WHICH VOLTAGE IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 "


Case Development

A-7


Model FRQTPAT Model Instance 80015509: FL FU PICKUP TB 0.000 61.800 2.010 0.000 BUS AT WHICH FREQUENCY IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model FRQTPAT Model Instance 80015510: FL FU PICKUP TB 0.000 60.500 600.679 0.000 BUS AT WHICH FREQUENCY IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model FRQTPAT Model Instance 80015511: FL FU PICKUP TB 59.500 100.000 1792.059 0.000 BUS AT WHICH FREQUENCY IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 " Model FRQTPAT Model Instance 80015512: FL FU PICKUP TB 57.800 100.000 5.010 0.000 BUS AT WHICH FREQUENCY IS MONITORED: 800155 GENERATOR BUS : 800155 MACHINE ID : "1 "


Case Development


A-8

A.7 IR36 Diagram


IR36kV: <=69.000 <=161.000<=115.000 <=230.000 <=345.000 <=500.000 <=765.000 >765.000

Bus - VOLTAGE (kV/PU)Branch - MW/MvarEquipment - MW/Mvar

2017 AUG DPP WEST PH2, SUMMER SHOULDERCIPCO IR36 STUDY CASESUN, FEB 09 2020 17:37

800155IR36 GEN

1.000.6

99.9

1.2

-99.1

4.71

100.0

1.6R

800156IR36 PAD

1.0034.4

800157IR36 COL

0.9934.3

99.1

-4.7 3.8

98.8

3.0

-98.4

10.5

13102IR-20_COL1

1.0034.6

52.9

-2.6

-52.7

6.7SW

-9.0

13101IR-20_COL

1.0034.5

53.3

-9.0

-52.9

11.7

-98.8

SW

-6.9

800158IR36 SUB

1.02164.1

631209COGGON 5

1.02164.1

-98.5

10.3

98.5

-10.3

13103IR-20 POI

1.02164.1

631147COFFEY5

1.02164.3

-10.4

1.1

10.4

-2.0

-36.6

8.4

36.7

-9.8

13104IR-20_HV

1.02164.1

1.02164.0

631051HAZLTON L2 5

1.02164.7

631100LIBERTY5

1.02164.2

-52.7

6.7

52.7

-6.7

63.2

-7.8

-63.1

7.5

92.2

-4.1

-91.5

5.8

150.3

-15.7

631089HIAWATA5

1.02164.7

631088ARNOLD 5

0.0

11.6

-0.0

-13.0

-126.4

6.6

SW

-43.9

636210WASHBRN5

-46.2

11.3

631050HAZLTON L1 5

1.02164.7

12.3

-46.8

-12.3

47.6

-74.5

47.6

15.4

27.9

-15.4

-27.6

631159HCKRYCK5

1.02164.4

119.1

-28.6

-118.9

29.7

-9.0

-12.711

9.0

12.8

631101DUNDEE 5

636200BLACKHAWK 5

-79.2

9.2

-27.0

18.7

613420WINDSOR5

629208COGGON J8

1.0471.6

-51.3

1.3

51.3

1.7

629209COGN MUNI 8

1.0471.5

630742RYAN REC 8

630881LINNBUCH8

1.0371.3

628904UNION TP8

1.0371.0

8.6

-0.3

-8.5

0.2

8.1

5.2

4.3

0.9

-4.3

-1.2

30.4

-7.1

AM0.7

0.2

4

J50.1

1.0270.5

-2.5

4.3

2.5

630017HIAWATA J1 8

1.0471.6

82.0

10.5

630256HAZLTON J2 8

1.0270.3

16.3

-8.1

630884WALKER REC8

3.1

1.1

7.9

-0.4

628905UNION R8

0.7

0.2

-8.5

0.8

28.8

-0.0

629210PARIS REC 8

1.2

630024DUNDEE 8

1.0270.2

630493SANDSPR8

-4.3

-28.8

29.0

630019LIBERTY8

1.0270.3

16.3

-8.1

630257HAZLTON J1 8

13100IR-20_GEN

1.000.7

53.6

-6.3

-53.3

9.01

53.6

-6.3R

631146COFFEY7

1.04120.2

631018HIAWATA7

631027SWAMPFX7

1.04119.8

-36.6

-4.2

36.6

4.6

44.5

15.2

-36.6

-4.3

36.6

4.2

J519.0

3.3

631019MARION K1 7

17.6

0.9

1.02351.9

SW

-0.0

631142ARNOLD 3

631191HCKRYCK3

1.03354.1

41814J1181 POI

251.5

-22.1

766.9

-62.9

-653.8

-2.9

67.9

-337.0

693863HLV 345

592.6

10.2

153.0

-9.8

SW

-158.1

631139HAZLTON3

631140SALEM 3

636199BLACKHAWK 3

1


Case Development

A-9




B-1


Appendix

B Contingency Analysis Results


B-1 CIPCO SPK P0 Thermal

1 of 1

Table B-1. CIPCO SPK P0 Thermal Constraints

IR36 PTDF>5%, OTDF>3%

100

DF

None

GIP With Impact-1Monitored Element Rating

Benchmark Case Study Case

Contingency label ContingencyOwner Type

Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading

(%)


B-2 CIPCO SPK P0 Voltage

1 of 1

Table B-2. CIPCO SPK P0 Voltage Constraints

Benchmark StudyCase

VLOW VHIGH VCONT VCONT IMPACT CONTINGENCY

None

Bus Area

Cont

Type


B-3 CIPCO SPK P1-P7 Thermal

1 of 1

Table B-3. CIPCO SPK P1-P7 Thermal Constraints


100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading

(%)


B-4 CIPCO SPK P1-P7 Voltage

1 of 1

Table B-4. CIPCO SPK P1-P7 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-5 CIPCO SPK N-2 Thermal

1 of 1

Table B-5. CIPCO SPK N-2 Thermal Constraints


100

DF

629208 COGGON J8 69.0

631209 COGGON 5 161 1

CIPCO 100 16.5 16.5 107.1 107.1 D:DUNDEE 5-IR-20 PO1 +COFFEY5 -COGGON 51DUNDEE 5 161 - IR-20 POI 161 1

COFFEY5 161 - COGGON 5 161 1

N-2 100.0% IR36,




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading

(%)


B-6 CIPCO SPK N-2 Voltage

1 of 1

Table B-6. CIPCO SPK N-2 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-7 MISO SPK P0 Thermal

1 of 1

Table B-7. MISO SPK P0 Thermal Constraints

IR36

100

DF GIP With Impact-1 GIP With Impact-2 GIP With Impact-3 GIP With Impact-4 GIP With Impact-5 GIP With Impact

None

Monitored Element Owner Rating


Contingency Type

Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading

(%) Contingency label

Outlet Mon. SummaryDF>5% MW>20%*Rating

Cum. MW>20%*Rating

& Ind. MW>5%*Rating Outlet Con.


B-8 MISO SPK P0 Voltage

1 of 1

Table B-8. MISO SPK P0 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-9 MISO SPK P1-P7 Thermal

1 of 1

Table B-9. MISO SPK P1-P7 Thermal Constraints

IR36

100


None



Contingency Type

Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading


Outlet Mon. SummaryDF>20% MW>20%*Rating

Cum. MW>20%*Rating



B-10MISO SPK P1-P7 Voltage

1 of 1

Table B-10. MISO SPK P1-P7 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-11 SPP SPK Thermal

1 of 1

Table B-11. SPP SPK Thermal Constraints

IR36 DF>3%

100

DF

None



GIP With Impact-1Contingency Type

Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-12 SPP SPK Voltage

1 of 1

Table B-12. SPP SPK Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-13 PJM SPK Thermal

1 of 1

Table B-13. PJM SPK Thermal Constraints

IR36 DF>5%

100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-14 PJM SPK Voltage

1 of 1

Table B-14. PJM SPK Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-15 AECI SPK Thermal

1 of 1

Table B-15. AECI SPK Thermal Constraints

IR36 Impact>3% of Rating

100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-16 AECI SPK Voltage

1 of 1

Table B-16. AECI SPK Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


Table B-17. SPK Non-Converged Contingencies

Contingency Contingency Details Type Benchmark Study

P22:161:AMMO::MOBERLY:1 345221 [5MOBERLY 161.00] TO 345222 [2MOBERLY 69.000] 1

345221 [5MOBERLY 161.00] TO 345222 [2MOBERLY 69.000] 2

345221 [5MOBERLY 161.00] TO 345409 [5OVERTON 161.00] 1

345221 [5MOBERLY 161.00] TO 543062 [SALSBRY5 161.00] 1

300126 [5MOBTAP 161.00] TO 345221 [5MOBERLY 161.00] Z1

P2-P7 Diverged Diverged

P23:161:AMMO::MOBERLY:16052 300126 [5MOBTAP 161.00] TO 345221 [5MOBERLY 161.00] Z1

300120 [5THMHILB1 161.00] TO 300126 [5MOBTAP 161.00] 1

300066 [5HIGBEE 161.00] TO 300126 [5MOBTAP 161.00] 1






P23:161:AMMO::PENOCREEK:H8 345439 [5PENOCRK 161.00] TO 345034 [5MARN TAP 161.00] 1

345497 [5PIKE 161.00] TO 345439 [5PENOCRK 161.00] 1

345497 [5PIKE 161.00] TO 346121 [2PIKE 69.000] 1

345497 [5PIKE 161.00] TO 346121 [2PIKE 69.000] 2


P24:138:AMIL::HENNEPIN:1302 348918 [4HENNEPIN S 138.00] TO 348934 [4HENNEPIN N 138.00] Z

271655 [HENNEEPIN; T138.00] TO 348918 [4HENNEPIN S 138.00] 1

348918 [4HENNEPIN S 138.00] TO 349536 [1HENNTT2 34.500] 2

348934 [4HENNEPIN N 138.00] TO 349527 [1HENNTT1 34.500] 1

348918 [4HENNEPIN S 138.00] TO 348919 [4LTV STL NTP138.00] 1

348918 [4HENNEPIN S 138.00] TO 348933 [4ESK TAP 138.00] 1

348918 [4HENNEPIN S 138.00] TO 349106 [1HENNEPIN G113.800] 1

348920 [4LTV STL ETP138.00] TO 348934 [4HENNEPIN N 138.00] 1

348934 [4HENNEPIN N 138.00] TO 348935 [4CORBIN 138.00] 1

348934 [4HENNEPIN N 138.00] TO 349107 [1HENNEPIN G215.500] 1

REMOVE UNIT H 349107 [1HENNEPIN G215.500]

REMOVE UNIT L 349107 [1HENNEPIN G215.500]


P24:161:AMMO::PIKE:16082 345497 [5PIKE 161.00] TO 345498 [5PIKE S 161.00] Z

345497 [5PIKE 161.00] TO 346121 [2PIKE 69.000] 1

345497 [5PIKE 161.00] TO 346121 [2PIKE 69.000] 2

345439 [5PENOCRK 161.00] TO 345497 [5PIKE 161.00] 1

344240 [5CALUMET 161.00] TO 345498 [5PIKE S 161.00] 1

344240 [5CALUMET 161.00] TO 346028 [2CALUMET 69.000] 1


P55:161:MEC:SYCAMORE 161 BUS 1 OR 2-KEEP AMES TIE 635701 [SYCAMOR5 161.00] TO 635705 [ANKENY 5 161.00] 1

635665 [FORVER 5 161.00] TO 635701 [SYCAMOR5 161.00] 1

635617 [JOHNSTON 5 161.00] TO 635701 [SYCAMOR5 161.00] 1

635685 [34 NW 5 161.00] TO 635703 [DELWARE5 161.00] 1

635600 [GRIMES 3 345.00] TO 635700 [SYCAMOR3 345.00] 1


635700 [SYCAMOR3 345.00] TO 635701 [SYCAMOR5 161.00] TO

635706 [SYCA1XT9 13.800] 1


635707 [SYCA2XT9 13.800] 2

635702 [SYCAMOR1 8 69.000] TO 635708 [SYCAMRG1 13.800] 1


635701 [SYCAMOR5 161.00] TO 635704 [SYCAMOR2 8 69.000] 2




B-18 CIPCO SH P0 Thermal

1 of 1

Table B-18. CIPCO SH P0 Thermal Constraints


100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-19 CIPCO SH P0 Voltage

1 of 1

Table B-19. CIPCO SH P0 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-20 CIPCO SH P1-P7 Thermal

1 of 1

Table B-20. CIPCO SH P1-P7 Thermal Constraints


100

DF

630019 LIBERTY8 69.0

631100 LIBERTY5 161 1

CIPCO 84 101.5 120.9 107.2 127.6 P7:161-345:ITCM:LIBERTY5-HCKRYCK5 HAZLETON3-HCKRYCK3:IA-NELIBERTY5 161 - HCKRYCK5 161 1

HCKRYCK3 345 - HAZLTON3 345 1

P2-P7 5.6% IR36




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-21 CIPCO SH P1-P7 Voltage

1 of 1

Table B-21. CIPCO SH P1-P7 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-22 CIPCO SH N-2 Thermal

1 of 1

Table B-22. CIPCO SH N-2 Thermal Constraints


100

DF

630019 LIBERTY8 69.0

631100 LIBERTY5 161 1

CIPCO 84 101.5 120.9 107.2 127.6 D:LIBERTY5-HCKRYCK51 +HAZLTON3-HCKRYCK31LIBERTY5 161 - HCKRYCK5 161 1

HAZLTON3 345 - HCKRYCK3 345 1

N-2 5.6% IR36

629208 COGGON J8 69.0

631209 COGGON 5 161 1

CIPCO 100 52.8 52.8 152.6 152.6 D:DUNDEE 5-IR-20 PO1 +COFFEY5 -COGGON 51DUNDEE 5 161 - IR-20 POI 161 1

COFFEY5 161 - COGGON 5 161 1

N-2 99.8% IR36




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-23 CIPCO SH N-2 Voltage

1 of 1

Table B-23. CIPCO SH N-2 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-24 MISO SH P0 Thermal

1 of 1

Table B-24. MISO SH P0 Thermal Constraints

IR36

100


None



Outlet Mon. SummaryPre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading

(%) Contingency Type

DF>5% MW>20%*Rating

Cum. MW>20%*Rating


Contingency label


B-25 MISO SH P0 Voltage

1 of 1

Table B-25. MISO SH P0 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-26 MISO SH P1-P7 Thermal

1 of 1

Table B-26. MISO SH P1-P7 Thermal Constraints

IR36

100


None



Outlet Mon. SummaryPre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading

(%) Contingency Type

DF>20% MW>20%*Rating

Cum. MW>20%*Rating


Contingency label


B-27 MISO SH P1-P7 Voltage

1 of 1

Table B-27. MISO SH P1-P7 Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-28 SPP SH Thermal

1 of 1

Table B-28. SPP SH Thermal Constraints

IR36 DF>3%

100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-29 SPP SH Voltage

1 of 1

Table B-29. SPP SH Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-30 PJM SH Thermal

1 of 1

Table B-30. PJM SH Thermal Constraints

IR36 DF>5%

100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-31 PJM SH Voltage

1 of 1

Table B-31. PJM SH Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


B-32 AECI SH Thermal

1 of 1

Table B-32. AECI SH Thermal Constraints

IR36 Impact>3% of Rating

100

DF

None




Pre Loading

(MVA)

Pre Loading

(%)

Post Loading

(MVA)

Post Loading



B-33 AECI SH Voltage

1 of 1

Table B-33. AECI SH Voltage Constraints

Benchmark StudyCase


None

Bus Area

Cont

Type


Table B-34. SH Non-Converged Contingencies

Contingency Contingency Details Type Benchmark Study

P22:161:AMMO::MOBERLY:1 345221 [5MOBERLY 161.00] TO 345222 [2MOBERLY 69.000] 1




300126 [5MOBTAP 161.00] TO 345221 [5MOBERLY 161.00] Z1


P23:161:AMMO::MOBERLY:16052 300126 [5MOBTAP 161.00] TO 345221 [5MOBERLY 161.00] Z1

300120 [5THMHILB1 161.00] TO 300126 [5MOBTAP 161.00] 1

300066 [5HIGBEE 161.00] TO 300126 [5MOBTAP 161.00] 1






P24:138:AMIL::EASTSPRINGFIELD:1390 349658 [4E SPFLD 138.00] TO 349691 [1E SPFLD 34.500] 1

349658 [4E SPFLD 138.00] TO 349691 [1E SPFLD 34.500] 2

349658 [4E SPFLD 138.00] TO 349691 [1E SPFLD 34.500] 3

343505 [4INTERSTA 138.00] TO 349658 [4E SPFLD 138.00] 1

343548 [4EASTDAL 98 138.00] TO 349658 [4E SPFLD 138.00] 1

348950 [4SHOCKEY 138.00] TO 349658 [4E SPFLD 138.00] 1


P24:138:AMIL::HENNEPIN:1302 348918 [4HENNEPIN S 138.00] TO 348934 [4HENNEPIN N 138.00] Z

271655 [HENNEEPIN; T138.00] TO 348918 [4HENNEPIN S 138.00] 1

348918 [4HENNEPIN S 138.00] TO 349536 [1HENNTT2 34.500] 2

348934 [4HENNEPIN N 138.00] TO 349527 [1HENNTT1 34.500] 1

348918 [4HENNEPIN S 138.00] TO 348919 [4LTV STL NTP138.00] 1

348918 [4HENNEPIN S 138.00] TO 348933 [4ESK TAP 138.00] 1

348918 [4HENNEPIN S 138.00] TO 349106 [1HENNEPIN G113.800] 1

348920 [4LTV STL ETP138.00] TO 348934 [4HENNEPIN N 138.00] 1

348934 [4HENNEPIN N 138.00] TO 348935 [4CORBIN 138.00] 1

348934 [4HENNEPIN N 138.00] TO 349107 [1HENNEPIN G215.500] 1

REMOVE UNIT H 349107 [1HENNEPIN G215.500]

REMOVE UNIT L 349107 [1HENNEPIN G215.500]


P24:161:SMMPA:RUTLAND5 7896:MN 613370 [RUTLAND5 161.00] TO 631042 [FOX LK 5 161.00] 1

613370 [RUTLAND5 161.00] TO 631045 [HUNTLEY5 161.00] 1

613370 [RUTLAND5 161.00] TO 613350 [RUTLAND 69.000] 1

613370 [RUTLAND5 161.00] TO 613350 [RUTLAND 69.000] 2


P55:161:MEC:SYCAMORE 161 BUS 1 OR 2-KEEP AMES TIE 635701 [SYCAMOR5 161.00] TO 635705 [ANKENY 5 161.00] 1

635665 [FORVER 5 161.00] TO 635701 [SYCAMOR5 161.00] 1

635617 [JOHNSTON 5 161.00] TO 635701 [SYCAMOR5 161.00] 1

635685 [34 NW 5 161.00] TO 635703 [DELWARE5 161.00] 1




635706 [SYCA1XT9 13.800] 1


635707 [SYCA2XT9 13.800] 2







Contingency Analysis Results


B-2



C-1


Appendix

C Short Circuit Analysis Results


C-1 Short Circuit Results1 of 1

Table C-1. Single-Line-to-Ground (SLG) and Three Phase (3PH) Fault Currents

Substation # Name kV Owner

SLG Fault Current

(A)

3PH Fault Current

(A)

SLG Fault Current

(A)

3PH Fault Current

(A) SLG 3PH SLG 3PH IR36SUB 800158 IR36SUB 161 CIPCO - - 9685.7 9809.3 - - - -COGGON 629208 COGGON 69 J1 69 CIPCO 8697.2 8885.2 13841.5 12549.8 5144.3 3664.6 59% 41%COGGON 391 COGGON 69 J2 69 CIPCO 8697.2 8885.2 13841.5 12549.8 5144.3 3664.6 59% 41%COGGON 631209 COGGON 161 161 CIPCO 7838.6 9250.6 9717.8 9833.8 1879.2 583.2 24% 6%IR20 13103 IR20SUB 161 CIPCO 7960.5 9404.3 8645.5 9780.7 685.0 376.4 9% 4%COFFEY 631147 COFFEY_L1 161 ITCM 9769.7 11173.9 10460.7 11491.9 691.0 318.0 7% 3%COFFEY 900287 COFFEY_L2 161 ITCM 9769.7 11173.9 10460.7 11491.9 691.0 318.0 7% 3%COFFEY 900288 COFFEY_L3 161 ITCM 9769.7 11173.9 10460.7 11491.9 691.0 318.0 7% 3%COFFEY 900289 COFFEY_L4 161 ITCM 9769.7 11173.9 10460.7 11491.9 691.0 318.0 7% 3%RADIO 630747 RADIO J1 69 ITCM 6020.1 9344.5 6088.5 9578.0 68.4 233.5 1% 2%SANDSPRINGS 630493 SANDSPN 69 69 ITCM 5582.7 6248.7 5680.1 6401.3 97.4 152.6 2% 2%DUNDEE 631101 DUNDEE 161 161 CIPCO 9233.7 11183.2 9568.2 11448.7 334.5 265.5 4% 2%COFFEY 631146 COFFEY_K1 115 ITCM 10702.8 10813.2 10903.9 11040.7 201.1 227.5 2% 2%HIAWATHA 630017 HIAWATHA J1 69 ITCM 21317.7 20605.8 21403.2 20951.7 85.5 345.9 0% 2%HIAWATHA 630760 HIAWATHA J2 69 ITCM 21317.7 20605.8 21403.2 20951.7 85.5 345.9 0% 2%HIAWATHA 313 HIA DIST TAP 69 ITCM 20567.1 20309.8 20645.5 20648.6 78.4 338.8 0% 2%MONTICELLOINDUSTRIA 630843 MONT IND J1 69 Alliant 4122.2 5166.5 4166.2 5251.4 44.0 84.9 1% 2%MONTICELLOINDUSTRIA 900363 MONT IND J2 69 Alliant 4122.2 5166.5 4166.2 5251.4 44.0 84.9 1% 2%MONTICELLOINDUSTRIA 1872 MONT J1 FUT 69 Alliant 4122.2 5166.5 4166.2 5251.4 44.0 84.9 1% 2%SWAMPFOX 631027 SWMPFOX115K1 115 Alliant 9124.2 10990.1 9181.1 11168.3 56.9 178.2 1% 2%SWAMPFOX 900054 SWMPFOX115K2 115 Alliant 9124.2 10990.1 9181.1 11168.3 56.9 178.2 1% 2%MARION 1172 MARION 69J1 69 ITCM 17411.5 18174.6 17472.6 18460.1 61.1 285.5 0% 2%MARION 630759 MARION 69J2 69 ITCM 17411.5 18174.6 17472.6 18460.1 61.1 285.5 0% 2%HIAWATHA 11 Hiawatha Cap 161 ITCM 15914.0 16513.5 16214.7 16746.5 300.7 233.0 2% 1%HIAWATHA 631089 HIAWATHA L1 161 ITCM 15914.0 16513.5 16214.7 16746.5 300.7 233.0 2% 1%HIAWATHA 900126 HIAWATHA L3 161 ITCM 15914.0 16513.5 16214.7 16746.5 300.7 233.0 2% 1%HIAWATHA 900127 HIAWATHA L4 161 ITCM 15914.0 16513.5 16214.7 16746.5 300.7 233.0 2% 1%HIAWATHA 900129 HIAWATHA L6 161 ITCM 15914.0 16513.5 16214.7 16746.5 300.7 233.0 2% 1%HIAWATHA 900128 HIAWATHA L5 161 ITCM 15914.0 16513.5 16214.7 16746.5 300.7 233.0 2% 1%MARION 631019 MARION 115K1 115 ITCM 13152.4 15562.8 13195.3 15763.9 42.9 201.1 0% 1%MARION 631195 MARION 115K2 115 ITCM 13152.4 15562.8 13195.3 15763.9 42.9 201.1 0% 1%OLDSETTLERS 631167 OLD SETTL K1 115 ITCM 12129.8 14689.4 12162.3 14876.7 32.5 187.3 0% 1%OLDSETTLERS 900404 OLD SETTL K2 115 ITCM 12129.8 14689.4 12162.3 14876.7 32.5 187.3 0% 1%EMERALDISLE 629380 Emerald I J1 69 ITCM 13074.6 16385.6 13102.5 16591.0 27.9 205.4 0% 1%EMERALDISLE 900353 Emerald I J2 69 ITCM 13074.6 16385.6 13102.5 16591.0 27.9 205.4 0% 1%DRYCREEK 631031 DRYCRK115K1 115 ITCM 12299.3 14443.8 12324.4 14623.2 25.1 179.4 0% 1%DRYCREEK 90055 DRYCRK115K2 115 ITCM 12299.3 14443.8 12324.4 14623.2 25.1 179.4 0% 1%HIAWATHA 631018 HIAWATHA 115 115 ITCM 16248.9 16024.1 16282.2 16218.7 33.3 194.6 0% 1%COLLINSNW69CR 629185 COLLINS J1 69 ITCM 10630.6 13743.0 10652.4 13906.2 21.8 163.2 0% 1%COLLINSNW69CR 1171 COLLINS J2 69 ITCM 10630.6 13743.0 10652.4 13906.2 21.8 163.2 0% 1%

Faulted BusBenchmark Case

without IR36Study Case with IR36 Impact (Ampere) Impact (%)


C-2 SCR1 of 1

Table C-2. Short Circuit Ratios

Contingency Type 3PH SCMVARated OutputIR20+IR36 CSCR Ratio

BASE CASE P0 986 154 6.4COGGON5 161 - COFFEY5 161 631209 [COGGON 5 161.00] - 631147 [COFFEY5 161.00] CKT 1

P1 830 154 5.4

COGGON5 161 - COGGON J8 69 631209 [COGGON 5 161.00] - 629208 [COGGON J8 69.000] CKT 1

P1 958 154 6.2

IR20 161 - DUNDEE5 161 13103 [IR-20 161.00] - 631101 [DUNDEE 5 161.00] CKT 1

P1 770 154 5.0

COFFEY5 161 - HIAWATA 161 631147 [COFFEY5 161.00] - 631089 [HIAWATA5 161.00] CKT 1

P1 912 154 5.9

COFFEY5 161 - COFFEY7 115 631147 [COFFEY5 161.00] - 631146 [COFFEY7 115.00] CKT 1

P1 978 154 6.4

COGGON5 161 - COFFEY5 161::COGGON5 161 - COGGON J8 69 631209 [COGGON 5 161.00] - 631147 [COFFEY5 161.00] CKT 1 631209 [COGGON 5 161.00] - 629208 [COGGON J8 69.000] CKT 1

N-2 743 154 4.8

COFFEY5 161 - COFFEY7 115::IR20 161 - DUNDEE5 161 631147 [COFFEY5 161.00] - 631146 [COFFEY7 115.00] CKT 1 13103 [IR-20 161.00] - 631101 [DUNDEE 5 161.00] CKT 1

N-2 753 154 4.9

COFFEY5 161 - HIAWATA 161::IR20 161 - DUNDEE5 161 631147 [COFFEY5 161.00] - 631089 [HIAWATA5 161.00] CKT 1 13103 [IR-20 161.00] - 631101 [DUNDEE 5 161.00] CKT 1

N-2 606 154 3.9

COGGON5 161 - COFFEY5 161::COGGON5 161 - IR20 161 631209 [COGGON 5 161.00] - 631147 [COFFEY5 161.00] CKT 1 631209 [COGGON 5 161.00] - 13103 [IR-20 161.00] CKT 1

N-2 302 100 3.0

COGGON5 161 - COFFEY5 161::IR20 161 - DUNDEE5 161 631209 [COGGON 5 161.00] - 631147 [COFFEY5 161.00] CKT 1 13103 [IR-20 161.00] - 631101 [DUNDEE 5 161.00] CKT 1

N-2 391 154 2.5


Short Circuit Analysis Results


C-2



D-1


Appendix

D Transient Stability Analysis Results


D-1 Transient Stability1 of 1

Table D-1. Transient Stability Analysis Results Summary

Disturbance Name DescriptionNERC

Category Area Angular Stability and Line Tripping Voltage and Dampingp0 No disturbance P0 OK OKP12_Coggon_IR20_161 3PH fault on Coggon to IR20 161 kV line; cleared at 6 cycles. P12 IR36 OK OKP12_Coggon_Coffey_161 3PH fault on Coggon to Coffey 161 kV line; cleared at 6 cycles. P12 IR36 OK OKP12_IR20_Dundee_161 3PH fault on IR-20 POI to Dundee 161 kV line; cleared at 6 cycles. P12 IR36 OK OK

P12_Coffey_Hiawatha_161 3PH fault on Coffey to Hiawatha 161 kV line; cleared at 6 cycles. P12 IR36 OK OKP12_Dundee_Hazleton_161 3PH fault on Dundee to Hazleton 161 kV line; cleared at 6 cycles. P12 IR36 OK OKP42_Coggon_IR20_161 SLG fault on Coggon to IR20 161 kV line; breaker fails at Coggon;

cleared at 18 cycles by tripping Coggon 161-69 kV xfmr. P42 IR36 OK OK

P42_Coggon_Coffey_161 SLG fault on Coggon to Coffey 161 kV line; breaker fails at Coggon; cleared at 18 cycles by tripping Coggon 161-69 kV xfmr.

P42 IR36 OK OK

P42_Dundee_Liberty_161 SLG fault on Dundee to Liberty 161 kV line; breaker fails at Dundee; cleared at 18 cycles by disconnecting Dundee 161 kV bus.

P42 IR36 OK OK

P42_Hiawatha_Arnold_161 SLG fault on Hiawatha to Arnold 161 kV line; breaker fails at Hiawatha; cleared at 18 cycles by tripping Hiawatha capacitor.

P42 IR36 OK OK

P611_Coggon-Coffey_Coggon-IR20_161 Prior outage of Coggon-Coffey 161. 3PH fault on Coggon-IR-20 161 kV line; cleared at 6 cycles.

P611 IR36 OK OK

P611_IR20-Dundee_Coggon-Coffey_161 Prior outage of IR20-Dundee 161. 3PH fault on Coggon to Coffey 161 kV line; cleared at 6 cycles.

P611 IR36 OK OK

P611_IR20-Dundee_Coffey-Hiawatha_161 Prior outage of IR20-Dundee 161. 3PH fault on Coffey-Hiawatha 161 kV line; cleared at 6 cycles.

P611 IR36 OK OK

0699_w_itcm_p11_auto_at_629074_1 3ph fault at bus arnold1g 22.000 with normal clearing P11 ITCM OK OK0703_w_itcm_p12_arnold_hazleton 3ph fault at arnold 345 kv bus with normal clearing on arnold-

hazleton 345 kv lineP12 ITCM OK OK

0708_w_itcm_p12_cmvp_hazlton3_blackhawk_fr 3ph fault; generic clearing; on HAZLTON3 - BLACKHAWK; at HAZLTON3 345

P12 ITCM OK OK

0717_w_itcm_p43_arn_haz_bk0710 slg fault on arnlod-hazleton 345 kv w/ failed arnold brkr 0710. dly clr morgan valley-arnold 345kv, arnold 345/161 kv

P43 ITCM OK OK

0719_w_itcm_p42_arnold_hazleton_bk4730 slg fault at arnold-hazleton 345 kv w/ failed brkr 0710. po of arnold-fairfax 161 kv. dly clr morgan v-arnold, 345/161

P42 ITCM OK OK

0720_w_itcm_p42_arnold_morgan_valley_bk2820 slg fault on arnold-morgan valley 345 kv w/ failed brkr 2820. delayed clearing on arnold 345/161 kv

P42 ITCM OK OK

0721_w_itcm_p42_arnold_fairfax_bk3110 slg fault on arnold-fairfax 161 kv w/ failed brkr 3110. delayed clearing on arnold-vinton 161 kv

P42 ITCM OK OK


Transient Stability Analysis Results


D-2



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