MPC02100 TSR System Impact Study for MPC Network … TSR System Impact Study for MPC Network Service...

MPC02100 TSR System Impact Study for MPC Network Service and

Point to Point Service to MISO Border Transmission Service Provider: Minnkota Power Cooperative, Inc.

Study Engineer: Aaron Vander Vorst

February 11, 2016

Source Type OASIS Ref# Queue Date Size Start Date

MPC02100 Network 82005059 12/18/2015 100 MW 9/1/2016

MPC02100 Point-to-Point 82005031 12/18/2015 100 MW 9/1/2016

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0 Executive Summary The purpose of this System Impact Study is to evaluate long term Network and Point-to-Point (“PTP”) Transmission Service Requests (“TSRs”) from Minnkota Power Cooperative (“Minnkota”) Generation Interconnection Request (“GIR”) MPC02100 to receive a) firm Network Transmission Service within Minnkota’s transmission system and b) firm PTP Transmission Service across Minnkota’s transmission system to the Midcontinent ISO (“MISO”) border. The following table lists the TSRs which are evaluated herein: Table 1: Study TSRs

OASIS Ref# Source Sink Service Type Size Start Date Queue Date

82005059 MPC02100 OTP.MPC MPC Yearly Network 100 MW 9/1/2016 12/18/2015

82005031 MPC02100 OTP.OTP MPC Yearly Point-to-Point 100 MW 9/1/2016 12/18/2015

Based on engineering review of the proximity of the MPC02100 POI with respect to Minnkota dispatchable generation, a delivery from MPC02100 to Minnkota’s dispatchable network resources would provide counter flow on all circuits between MPC02100 and the sink for the Network TSR analysis. Therefore, Minnkota determined that a System Impact Study for the MPC02100 Network TSR is not necessary and that the TSR may be accepted. The PTP TSR which is being evaluated in this study is for service to the MISO footprint. As such, the analysis is being performed to grant firm rights to deliver power across the MPC system to the border with MISO. No service on the MISO transmission system is contemplated in this study. Therefore, this study identifies constraints on Minnkota’s transmission system and third party transmission systems, but does not limit service based on MISO transmission constraints1. The power flow models were developed from the recent MISO A634 TSR study models. Those models were subsequently updated by Minnkota for two prior-queued TSR studies. Models include 2014 summer peak, 2018 summer peak, and 2018 summer off-peak (shoulder) profiles. Minor updates were made to the modeling of TSRs and the transmission system. Steady state contingency analysis and Flowgate impact analysis were performed to identify constraints to granting the requested service. The following constraints to granting firm service were identified and must be mitigated prior to granting the TSRs. All constraints have been previously identified for upgrade by a prior queued project or in the MPC02100 Interconnection System Impact Study. Therefore, no Facility Studies are required as a result of this analysis.

1 Per the On-the-Path / Off-the-Path methodology found in Minnkota’s and MISO’s respective ATCID documents

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• MPC02100 Network TSR (#82005059)

o No constraints • MPC02100 Point-to-Point TSR to MISO border (#82005031)

o Service will be limited by loading on the Jamestown – Buffalo 345 kV line and corresponding Flowgate 6330 (JAMBUFCENMAN) only if the MISO GIR J262/J263 goes in service without having completed its required upgrade on this line.

o Service will be limited by Flowgate 6322 CENMANJAMBIS starting 6/18/2017 if MPC02100 has not completed the upgrade of the Roughrider – Mandan 230 kV line which is required for interconnection service.

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Table of Contents 0 Executive Summary ............................................................................................................................... 2 1 Introduction .......................................................................................................................................... 5 2 Model Development ............................................................................................................................. 6

2.1 Model Development Overview ..................................................................................................... 6 2.2 TSR Modeling ................................................................................................................................ 6 2.3 Post-project Case Development ................................................................................................... 7 2.4 Transmission Assumptions ............................................................................................................ 7

2.4.1 2014 Case .............................................................................................................................. 7 2.4.2 2018 Cases ............................................................................................................................ 7

3 Analysis Methodology and Criteria ....................................................................................................... 7 3.1 Facility Ratings .............................................................................................................................. 8 3.2 Contingencies and Monitored Elements....................................................................................... 8

3.2.1 Contingencies ........................................................................................................................ 8 3.2.2 Monitored Elements ............................................................................................................. 9

3.3 Constraint Identification ............................................................................................................. 10 4 Steady State Contingency Analysis ..................................................................................................... 10

4.1 Minnkota and Third Party (non-MISO) Results ........................................................................... 11 4.2 MISO Results ............................................................................................................................... 12 4.3 Discussion of Constraints ............................................................................................................ 15

4.3.1 Jamestown – Buffalo 345 kV Line Overload ........................................................................ 15 5 Flowgate Impact Analysis .................................................................................................................... 15

5.1 OASIS Automation Tool Results .................................................................................................. 15 5.2 Off-line Flowgate Impact Analysis............................................................................................... 15 5.3 Discussion of Constraints ............................................................................................................ 16

5.3.1 Flowgate 6330 Impact ......................................................................................................... 16 5.3.2 Flowgate 6322 Impact ......................................................................................................... 16 5.3.3 Flowgate 5028 Impact ......................................................................................................... 17

6 Summary of Results ............................................................................................................................ 17 Appendix A – Documentation of TSR Modeling.......................................................................................... 18

A.1 Minnkota Power Cooperative TSR Queue ........................................................................................ 18 A.2 Neighboring Transmission Service Provider TSR Queues ................................................................. 19

Appendix B –Contingency Screen Analysis Results ..................................................................................... 22 B.1 DC Contingency Screen Analysis Results .......................................................................................... 22 B.2 AC Contingency Screen Analysis Results ........................................................................................... 22

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1 Introduction The purpose of this System Impact Study is to evaluate long term Network and Point-to-Point (“PTP”) Transmission Service Requests (“TSRs”) from Minnkota Power Cooperative (“Minnkota”) Generation Interconnection Request (“GIR”) MPC02100 to receive a) firm Network Transmission Service within Minnkota’s transmission system and b) firm PTP Transmission Service across Minnkota’s transmission system to the Midcontinent ISO (“MISO”) border. The two services are not intended to be granted simultaneously, although each may be used in part, the sum not to exceed 100 MW. The two TSRs allow the source unit to deliver to either Minnkota or to the MISO border, but the total delivery from the source of the TSRs may not exceed 100 MW. The following table lists the TSRs which are evaluated herein: Table 2: Study TSRs

OASIS Ref# Source Sink Service Type Size Start Date Queue Date

82005059 MPC02100 OTP.MPC MPC Yearly Network 100 MW 9/1/2016 12/18/2015

82005031 MPC02100 OTP.OTP MPC Yearly Point-to-Point 100 MW 9/1/2016 12/18/2015

The Point of Interconnection (“POI”) for the MPC02100 project is at a new tap on the Center – Mandan 230 kV substation. The new substation is referred to at the Roughrider Substation herein and will be built as a three breaker ring bus. The generation project will be built using 2.0 MW GE wind turbine generators. Based on engineering review of the proximity of the MPC02100 POI with respect to Minnkota dispatchable generation, a delivery from MPC02100 to Minnkota’s dispatchable network resources would provide counter flow on all circuits between MPC02100 and the sink for the Network TSR analysis. Therefore, Minnkota determined that a System Impact Study for the MPC02100 Network TSR is not necessary and that the TSR may be accepted. The ad hoc group was consulted and did not raise any objections. The PTP TSR which is being evaluated in this study is for service to the MISO footprint. As such, the analysis is being performed to grant firm rights to deliver power across the MPC system to the border with MISO. No service on the MISO transmission system is contemplated in this study. Therefore, this study identifies constraints on Minnkota’s transmission system and third party transmission systems, but does not limit service based on MISO transmission constraints2.

2 Per the On-the-Path / Off-the-Path methodology found in Minnkota’s and MISO’s respective ATCID documents

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2 Model Development

2.1 Model Development Overview The power flow models were developed from the recent MISO A634 TSR study models. The A634 models were used by MISO to evaluate a number of TSRs in central and western North Dakota (A617, A618, A626, and A634). Those models were subsequently updated by Minnkota for two studies evaluating TSRs 73373269, 73373331, 73373336, 73373341, 73603991, 73603996, 73603999, 73604002, 73604005, 73604010, 3604015, 73604018, and 810229043. The post-project cases for TSR 81022904, along with model updates identified in the two studies, were applied to the cases. Models include 2014 summer peak, 2018 summer peak, and 2018 summer off-peak (shoulder) profiles. The 2014 model includes 2015 TSRs and transmission. The 2018 models include future TSRs and transmission with a high degree of certainty. Specific model revisions are described below. Model development was performed using Siemens PTI’s PSS/E version 32 and the UMTAG study package 2012Series_UMTAG_08-13-2013. Ad hoc invitations were sent to BEPC, CPEC, GRE, MDU, MH, MISO, MP, MRES, OTP, SPP, WAPA, and XCEL. The study plan, study models, and draft report were submitted to the ad hoc group for review and all comments received were addressed.

2.2 TSR Modeling TSRs in the Minnkota, MISO, SPP, and MH queues (as posted on the OASIS) were reviewed and included if they were prior queued and resulted in parallel flows with the TSRs under study. Any adjustment to a TSR source was dispatched to the control area defined in the TSR sink, unless doing so would result in a reduction of other local TSR sources. In that case, specific generators were targeted which would produce parallel flows to the TSR under study. A listing of the modeled TSRs from Minnkota’s OASIS and the OASIS sites of neighboring TSPs can be found in the appendices. A few notes on TSR modeling are provided below. TSRs covering Minnkota network load and other prior queued firm reservations, including delivery to MISO, were verified in the cases. Modeling of the MISO TSR queue was generally complete as the cases were previously used by MISO for TSR studies sourcing in North Dakota. Modeling of MISO TSRs and NRIS units sourcing in the electrical vicinity of the TSRs under study was reviewed. A few minor adjustments were applied to ensure all TSRs with common impacts were modeled. MISO staff was contacted to confirm the modeling of MISO TSRs.

3 These TSR numbers are listed as seen in their respective System Impact Studies. For a mapping to the currently posted TSR number for each of these requests, please see the Minnkota OASIS page.

https://www.oasis.oati.com/MPCN/index.html

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On 10/1/2015, the Integrated System, including WAPA and BEPC, joined SPP. The WAPA TSR queue was transitioned to the SPP OASIS. It was determined from review with WAPA and SPP that the WAPA TSRs used in the previous studies were the same as the currently posted SPP TSRs. TSR dispatch was adjusted slightly to ensure that TSRs which source from units closest to MPC02100 were modeled at their approved amount. TSRs are approved for 1848 MW of transfer across the existing MH-US interface. These TSRs were already included in the models. TSRs have been approved for an additional 883 MW in conjunction with a new 500 kV tie between Manitoba and the US. These TSRs and the associated transmission additions are included in the 2018 study cases. More details on related transmission additions can be found in subsequent sections.

2.3 Post-project Case Development Post-project cases were developed by turning on MPC02100 at 100 MW and sinking the power to the MISO footprint (included a set of 31 MISO LBAs). A few local MISO generators were excluded from the sink scaling to ensure local TSRs remained at their approved level of service.

2.4 Transmission Assumptions Minimal modifications were required on the transmission system as the models were updated during the prior TSR studies noted above. Major transmission assumptions are noted below.

2.4.1 2014 Case The following projects were included in the 2014 summer peak case:

• Center – Prairie 345 kV line • Bison – Alexandria 345 kV line • Brookings – Lyon County – Hazel 345 kV lines • Riel 500/230 kV substation

2.4.2 2018 Cases The following projects were included in the 2018 summer peak and 2018 summer shoulder cases:

• Keeyask hydro plant in northern Manitoba • MH Bipole III project • MH/MP Great Northern Transmission Line (Dorsey – Iron Range 500 kV line) • Phase shifting transformer on the Glenboro – Rugby 230 kV line • MISO 2011 MVP portfolio • Bagley West 230/115 kV transformer and Bagley West – Clearbrook West – Clearbrook 115 kV

line • BEPC AVS to Neset 345 kV transmission project (North Killdeer loop not included)

3 Analysis Methodology and Criteria Steady state contingency analysis was performed to identify constraints to granting the requested transmission service. Contingency analysis consisted of two steps. First, a contingency screen was run

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using a DC power flow solution in Siemens PTI’s PSS/MUST. Results from contingency screens with and without the TSR were compared and transfer distribution factors (“TDF”) were calculated. The resulting file was filtered by TDF to identify potential Significantly Affected Facilities (“SAF”). Then, a second contingency screen with a limited set of contingencies was run in PSS/MUST using an AC power flow solution to validate potential constraints. Flowgate impact analysis was performed in two distinct parts. For the first 18 months following the TSR queue date, results from the OASIS Automation Tool are reviewed to determine if constraints exist. Beyond the 18 month window, flowgates were evaluated using the steady state models.

3.1 Facility Ratings Facility ratings were included as established by the facility’s Transmission Owner(s) (“TO”). Thermal ratings are included in the study cases. For the purposes of this analysis, Rate A is the continuous (also referred to as normal) facility rating and Rate B is the emergency facility rating as established by the TO(s). Flowgate ratings were included as established by the NERC MOD standards, including reductions for TRM and CBM. Voltage criteria can be seen in the table below. Table 3: Transmission Owner Voltage Criteria

Area Base kV System Intact

Conditions N-1 Contingency

Conditions Max (pu) Min (pu) Max (pu) Min (pu)

Regional Default* 115-500 kV 1.05 0.95 1.10 0.90 Xcel (Area 600) 115-500 kV 1.05 0.95 1.05 0.92 MP (Area 608) 115-500 kV 1.05 1.00 1.10 0.95 OTP** (Area 620) 115-500 kV 1.05 0.97 1.10 0.92 MH (Area 667) 110, 220 kV 1.10 0.99 1.15 0.94 *Includes areas 600, 608, 615, 620, 652, 661, 667 unless modified **MPC is in the OTP area. MPC voltage criteria is the same as was used for the OTP area

Unique criteria applied to: At the following buses: GRE Hubbard, Wing River, Ramsey Xcel Series, shunt capacitor buses WAPA Phillip

3.2 Contingencies and Monitored Elements

3.2.1 Contingencies Each case required a unique set of contingencies. To accomplish this individual treatment of cases, a parent file was used to call multiple contingency files specific to the study case. Contingency selection

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and categorization was based on NERC standard TPL-001-4. The following contingency files were utilized:

• Standard MRO contingency files from the 2014 model series. Error logs were reviewed to identify discrepancies between the files and the cases. Updates were made to contingencies which were potentially impactful. Contingency types P0, P1, P2, P4, P5, and P7 were included for the Dakotas, Minnesota, and Manitoba. Some of these contingency types are included for informational purposes only.

• P1 contingencies which involve a MH-US tie line were developed to include case-specific runback amounts and cross-tripping schemes which reflect actual operation of the MH HVdc runback scheme per its current design settings.

• A small set of P3 contingencies was developed based on engineering judgment. If a potential constraint resulted from a P3 contingency, the violation was reviewed as follows. Generation from the BA/LBA of the outaged generator was turned up to cover the loss of resource. If sufficient capacity was not available from the BA/LBA, the associated RTO’s contingency reserve sharing group was utilized to cover the remainder. Curtailment of firm service from another unit was not permitted as a system adjustment in order to grant firm service to a new unit.

• Single line and tie line contingencies (100 kV and above) and single generator contingencies were included from the GRE, MDU, MH, MP, OTP, WAPA, and XCEL control areas. MH single branch contingencies were limited to those between 200 and 400 kV, as sub-200 kV contingencies are electrically remote and 500 kV contingencies are modeled with their proper runbacks. The MH P1 file covers a large number of the sub-200 kV MH single contingencies.

For each potentially constrained element identified in the DC screen, at least five of the most limiting contingencies associated with that element were included in the AC screen.

3.2.2 Monitored Elements Facilities rated 115 kV and above in the GRE, MDU, MH, MP, OTP, WAPA, and XCEL areas were monitored for thermal and voltage violations in the power flow contingency screens. Facilities rated 69 kV and above in the OTP control area were monitored. For the DC power flow screen, facilities were flagged at 90% of continuous rating. If the pre-project loading was below 80% of continuous rating, it was not captured. The twenty contingencies which resulted in the highest loading with a TDF of at least 2.9% were reported for each monitored element. In the AC power flow screen, facilities that were loaded above 100% of continuous ratings were flagged. If the pre-project loading was below 85% of continuous rating, it was not captured. Results were retained if the TSR had a TDF greater than 3%. Facilities outside their applicable voltage criteria were flagged. Voltage violation results were retained if the TSR had an impact greater than 1%. The latest flowgate monitoring files were obtained from MISO and were included in the monitored elements file. For flowgates involving the Center – Mandan 230 kV line, the Center 230 kV bus was

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replaced with the Roughrider 230 kV substation4. Flowgates were monitored using the same screening criteria as thermal elements in the steady state contingency analysis.

3.3 Constraint Identification Constraint identification was performed in accordance with the MPC Transmission Planning BPM5. Significantly Affected Facilities (“SAF”) are defined as any transmission facility, 100 kV and above (for transformers, at least two windings must be connected at 100 kV or above), for which all of the following conditions exist:

1. In the post-project case, the facility exceeds its continuous thermal or voltage rating. 2. The increase in the loading of the facility from the pre-project to the post-project case is greater

than 1 MVA (1 MW in a DC screen). 3. The project has greater than a 3% TDF or 0.01 p.u. change in voltage. Equations for TDF

calculations are shown below (MVA flow replaces MW flow for AC analysis). Mitigation of SAF is required if all of the following conditions exist:

• Violation is the result of a contingency type in Table 1 of the NERC Standard TPL-001-4 which does not permit interruption of firm transmission service. Violations which resulted from contingencies for which interruption of firm service is allowed can be seen in the DC screen results in the appendices.

• The violation exceeds the applicable rating (normal rating for System Intact conditions or emergency rating for post-contingent conditions)

• The violation exceeds impact criteria of 5% TDF for system intact or 3% TDF for post-contingent. Mitigation of transmission constraints owned exclusively by MISO members is not required for Minnkota to grant the TSRs. Such constraints will be reported to MISO for MISO’s consideration in the granting of service on the MISO transmission system.

4 Steady State Contingency Analysis Steady state results from the DC and AC contingency analysis can be seen in the appendices. The tables below contain the top five overloads from the AC contingency analysis for each monitored element.

4 The Roughrider 230 kV substation is a tap on the Center – Mandan 230 kV line which will be built to facilitate interconnection of MPC02100. Of the two resultant line sections, the Roughrider – Mandan 230 kV line is the more highly loaded element and also becomes the more limiting contingency. 5 https://www.oasis.oati.com/MPCN/MPCNdocs/MPC_Transmission_Planning_BPM_Oct_1_2015.pdf

https://www.oasis.oati.com/MPCN/MPCNdocs/MPC_Transmission_Planning_BPM_Oct_1_2015.pdf

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4.1 Minnkota and Third Party (non-MISO) Results The following tables show the overloads and voltage violations flagged on the transmission systems of Minnkota and non-MISO third parties which resulted from the TSRs. No voltage constraints were identified. Additional information on each facility is included in the notes column. A more detailed discussion of certain results is provided at the end of this section.

Table 4: MPC02100 PTP TSR AC Contingency Analysis Results - MPC and 3rd Party (non-MISO)

MPC02100-MISO, 100 MW Firm PTP

Monitored ElementNormal Rating

Emergency Rating

Pre-TSR MVA

Pre-TSR %RateA

Post-TSR MVA

Post-TSR %RateA

Post-TSR %RateB

TDF % Contingency Description Notes

705.0 705.0 725.5 102.9 747.7 106.1 106.1% 22.2%P32:345:MPC:899.0 SHERCO3 3:1:CENTER-PRAIRIE:CENTE

705.0 705.0 696.2 98.8 724.6 102.8 102.8% 28.4%P32:345:MPC:899.0 SHERCO3 3:1:MANDAN-CENTER:MANDAN

705.0 705.0 697.6 98.9 720.0 102.1 102.1% 22.4%P12:345:MPC:CENTER-PRAIRIE:CENTER 3:PRAIRIE3

106.0 128.0 115.8 109.3 119.6 112.9 93.4% 3.8%P12:230:OTP::ELLENDL4:HANKSON4:R2016

106.0 128.0 115.7 109.2 119.5 112.7 93.4% 3.8%620362 OAKES 4 230 620363 FORMAN 4 230 1

106.0 128.0 115.7 109.2 119.5 112.7 93.4% 3.8%P12:230:OTP::HANKSON4:OAKES 4:V2016

106.0 128.0 115.6 109.0 119.3 112.6 93.2% 3.7%620362 OAKES 4 230 661026 ELLENDL4 230 1



Emergency Rating

Pre-TSR MVA

Pre-TSR %RateA

Post-TSR MVA

Post-TSR %RateA

Post-TSR %RateB


705.0 705.0 720.6 102.2 742.0 105.3 105.2% 21.4%P32:345:MPC:899.0 SHERCO3 3:1:CENTER-PRAIRIE:CENTE


705.0 705.0 695.2 98.6 718.4 101.9 101.9% 23.2%P12:345:MPC:CENTER-PRAIRIE:CENTER 3:PRAIRIE3

705.0 705.0 681.2 96.6 708.5 100.5 100.5% 27.3%657741 ROUGHRIDER 4 230 661053 MANDAN 4 230 1



Emergency Rating

Pre-TSR MVA

Pre-TSR %RateA

Post-TSR MVA

Post-TSR %RateA

Post-TSR %RateB


Roughrider-Mandan 230 kV line 610.0 614.0 564.0 92.5 612.3 100.4 99.7% 48.3%P32:345:MPC:80.0 HESKETT3 7:1:JAMESTOWN-BISON:JAME

Does not exceed emergency rating

2018 Summer Peak

Jamestown-Buffalo 345 kV lineUprate by prior

queued J262/J263 is adequate

2018 Summer Off-Peak

2014 Summer Peak

Jamestown-Buffalo 345 kV lineUprate by prior queued J262/J263

adequate

Ellendale-Aberdeen Jct 115 kV lineDoes not exceed emergency rating

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4.2 MISO Results The following tables show the overloads flagged on the transmission systems of MISO members which resulted from the TSRs. No voltage constraints were identified. Additional information for each facility is included in the notes column. MISO constraints have been included in the tables below for informational purposes. As noted previously, mitigation of transmission constraints owned exclusively by MISO members is not required for Minnkota to grant the requested transmission service. Such constraints will be reported to MISO for MISO’s consideration in the granting of service on the MISO transmission system. Table 5: MPC02100 PTP TSR AC Contingency Analysis Results – 2014 Summer Peak – MISO Transmission System



Emergency Rating

Pre-TSR MVA

Pre-TSR %RateA

Post-TSR MVA

Post-TSR %RateA

Post-TSR %RateB


159.0 159.0 170.6 107.3 175.6 110.4 110.4% 5.0%601067 BISON 3 345 620358 BUFFALO3 345 1

159.0 159.0 162.4 102.1 167.2 105.2 105.2% 4.8% P23:345:MPC:BISON 3:6710

159.0 159.0 162.3 102.1 167.2 105.2 105.2% 4.9% P23:345:MPC:BISON 3:6730

159.0 159.0 162.2 102.0 167.0 105.1 105.0% 4.8% P23:345:MPC:BISON 3:6720

112.0 140.0 199.7 178.3 204.3 182.4 145.9% 4.6%601067 BISON 3 345 620358 BUFFALO3 345 1

112.0 140.0 194.3 173.4 198.8 177.5 142.0% 4.5% P23:345:MPC:BISON 3:6730

112.0 140.0 192.2 171.6 196.7 175.6 140.5% 4.5% P23:345:MPC:BISON 3:6710

112.0 140.0 192.0 171.4 196.5 175.4 140.4% 4.5% P23:345:MPC:BISON 3:6720

Coyote 345/115 kV tfmr 1 168.0 210.0 162.1 96.5 169.0 100.6 80.5% 6.9%P32:345:MPC:429.0 LELANDOLDS2 3:1:JAMESTOWN-BISON:


Heskett 230/115 kV tfmr 1 100.0 125.0 109.2 109.2 114.5 114.5 91.6% 5.3%P12:230.0:UMZY:# 218 #: HE-MDN in ND. Loss of Tran


Mapleton-Sheyenne 115 kV line

Buffalo 345/115 kV tfmr 1

MISO facility

MISO facility. Parallel

transformer planned (MTEP Project 3481)

2014 Summer Peak

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Table 6: MPC02100 PTP TSR AC Contingency Analysis Results – 2018 Summer Peak – MISO Transmission System



Emergency Rating

Pre-TSR MVA

Pre-TSR %RateA

Post-TSR MVA

Post-TSR %RateA

Post-TSR %RateB


159.0 159.0 197.4 124.2 203.8 128.2 128.2% 6.4%601067 BISON 3 345 620358 BUFFALO3 345 1

159.0 159.0 187.1 117.7 192.1 120.8 120.8% 5.0% P23:345:MPC:BISON 3:6710

159.0 159.0 186.7 117.4 191.9 120.7 120.7% 5.2% P23:345:MPC:BISON 3:6730

159.0 159.0 180.1 113.3 191.8 120.6 120.6% 11.7% P23:345:MPC:BISON 3:6720

112.0 140.0 229.8 205.2 235.6 210.3 168.3% 5.8%601067 BISON 3 345 620358 BUFFALO3 345 1

112.0 140.0 222.0 198.2 227.1 202.7 162.2% 5.1% P23:345:MPC:BISON 3:6730

112.0 140.0 220.1 196.5 224.8 200.7 160.6% 4.7% P23:345:MPC:BISON 3:6710

112.0 140.0 208.5 186.2 224.6 200.5 160.4% 16.1% P23:345:MPC:BISON 3:6720

168.0 210.0 187.2 111.4 194.2 115.6 92.5% 7.0%P32:345:MPC:429.0 LELANDOLDS2 3:1:JAMESTOWN-BISON:

168.0 210.0 177.6 105.7 191.4 113.9 91.1% 13.8%P32:345:MPC:429.0 LELANDOLDS2 3:1:MANDAN-CENTER:MA

168.0 210.0 180.4 107.4 187.2 111.4 89.1% 6.8%P32:345:MPC:80.0 HESKETT3 7:1:JAMESTOWN-BISON:JAME

168.0 210.0 180.1 107.2 186.6 111.1 88.9% 6.5%P12:345:MPC:JAMESTOWN-BISON:JAMESTN3:BISON 3

168.0 210.0 180.0 107.1 186.5 111.0 88.8% 6.5%620358 BUFFALO3 345 620369 JAMESTN3 345 1



Coyote-Beulah 115 kV line 120.0 120.0 116.0 96.6 120.6 100.5 100.5% 4.6%P32:345:MPC:429.0 LELANDOLDS2 3:1:JAMESTOWN-BISON:

MISO facility

Heskett 230/115 kV tfmr 1 100.0 125.0 94.1 94.1 101.3 101.3 81.0% 7.2%P12:230.0:UMZY:# 218 #: HE-MDN in ND. Loss of Tran


Merricourt-Ellendale MVP 230 kV line 319.0 383.0 358.2 112.3 368.2 115.4 96.1% 10.0%P12:230.0:UMZY:# 204 #: ELM-TAT in ND. Loss of Tra


Tatanka-Ellendale MVP 230 kV line 319.0 343.0 368.7 115.6 378.4 118.6 110.3% 9.7%P12:230.0:UMZY:# 203 #: ELM-MRT in ND. Loss of Tra

MISO facility



Coyote 345/115 kV tfmr 1

MISO facility




2018 Summer Peak

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Table 7: MPC02100 PTP TSR AC Contingency Analysis Results – 2018 Summer Off-Peak – MISO Transmission System



Emergency Rating

Pre-TSR MVA

Pre-TSR %RateA

Post-TSR MVA

Post-TSR %RateA

Post-TSR %RateB


Chisago 500/345 kV tfmr 9 1204.0 1299.0 1296.2 107.7 1304.2 108.3 100.4% 8.0% MHUS CHIS XFMR 10 MISO facility

Chisago 500/345 kV tfmr 10 1204.0 1299.0 1296.3 107.7 1304.4 108.3 100.4% 8.1% MHUS CHIS XFMR 9 MISO facility

Stanton-Leland Olds 230 kV line 285.0 285.0 301.3 105.7 327.2 114.8 114.8% 25.9%P32:345:MPC:429.0 LELANDOLDS2 3:1:MANDAN-CENTER:MA

MISO facility. Upgrade to circuit

identified in interconnection SIS

159.0 159.0 170.1 107.0 176.1 110.8 110.8% 6.0%601067 BISON 3 345 620358 BUFFALO3 345 1

159.0 159.0 158.2 99.5 163.5 102.8 102.8% 5.3% P23:345:MPC:BISON 3:6710

159.0 159.0 158.0 99.4 163.4 102.8 102.8% 5.4% P23:345:MPC:BISON 3:6730

159.0 159.0 158.0 99.4 163.3 102.7 102.7% 5.3% P23:345:MPC:BISON 3:6720

112.0 140.0 197.9 176.7 203.7 181.9 145.5% 5.8%601067 BISON 3 345 620358 BUFFALO3 345 1

112.0 140.0 188.2 168.1 193.5 172.8 138.2% 5.3% P23:345:MPC:BISON 3:6730

112.0 140.0 186.4 166.4 191.6 171.1 136.9% 5.2% P23:345:MPC:BISON 3:6710

112.0 140.0 186.2 166.3 191.4 170.9 136.7% 5.2% P23:345:MPC:BISON 3:6720





168.0 210.0 219.0 130.4 232.6 138.4 110.8% 13.6%P32:230:MPC:195.0 STANTON1 4:1:MANDAN-CENTER:MANDA





120.0 120.0 137.6 114.7 147.3 122.8 122.8% 9.7%P32:230:MPC:195.0 STANTON1 4:1:MANDAN-CENTER:MANDA

Merricourt-Ellendale MVP 230 kV line 319.0 383.0 354.8 111.2 363.9 114.1 95.0% 9.1%P12:230.0:UMZY:# 204 #: ELM-TAT in ND. Loss of Tra


Tatanka-Ellendale MVP 230 kV line 319.0 343.0 365.0 114.4 374.2 117.3 109.1% 9.2%P12:230.0:UMZY:# 203 #: ELM-MRT in ND. Loss of Tra

MISO facility

*Limited to top 10 results. Full results available in appendices



Coyote-Beulah 115 kV line

Coyote 345/115 kV tfmr 1

MISO facility



MISO facility

MISO facility


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4.3 Discussion of Constraints Mitigation information provided below is based on preliminary research and should not be considered binding in any way. If required, mitigation options and costs must be further reviewed through Facilities Studies with the appropriate Transmission Owner(s).

4.3.1 Jamestown – Buffalo 345 kV Line Overload An existing overload on the Jamestown – Buffalo 345 kV line was aggravated by the MPC02100 to MISO PTP TSR. The line was overloaded in the near term and out-year summer peak cases. The maximum observed flow was 748 MVA. The contingency was an outage of Sherco unit 3 followed by a contingency of the Center – Prairie 345 kV line. The line was also overloaded for the P1-2 version of the contingency involving only the Center – Prairie 345 kV line, therefore system adjustments were not tested. The transmission line is owned by Minnkota, while the majority of the equipment at the terminal substations is owned by OTP. A Facility Construction Agreement has been signed with Minnkota by MISO interconnection request J262/J263 to uprate this line to 842 MVA in 2016. This upgrade is adequate to mitigate impacts observed in the study. This upgrade must be completed prior to granting firm PTP transmission service from MPC02100 to the MISO border. Review of the Minnkota TSR SIS for TSR #810229046 indicates that if the project withdraws, the line will no longer be overloaded. Therefore, the Jamestown – Buffalo 345 kV line is not a constraint to granting the TSR for MPC02100 based on the steady state results. However, the MPC02100 PTP TSR will be limited if the J262/J263 generation is completed prior to completing the upgrade.

5 Flowgate Impact Analysis Flowgate impact results from the DC contingency analysis can be seen in the appendices.

5.1 OASIS Automation Tool Results The OASIS Automation Tool identifies constraints in Available Flowgate Capacity (“AFC”) for TSRs submitted on OASIS. No AFC constraints were identified in the first 18 months after the TSRs were posted.

5.2 Off-line Flowgate Impact Analysis The following tables show the Flowgate impacts which were flagged as a result of adding the MPC02100 PTP TSR. Additional information on each facility is included in the notes column. A more detailed discussion of certain results is provided at the end of this section.

6 TSR #81022904 is for transmission service across the Minnkota Transmission system for MISO GIR J262/J263

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Table 8: MPC02100 PTP TSR Flowgate Impact Results

*Note: Flowgates involving the Center – Mandan 230 kV line (CENMAN) were modified due to the MPC02100 project tapping this line. The Center 230 kV bus was replaced with the Roughrider 230 kV bus.

5.3 Discussion of Constraints Mitigation information provided below is based on preliminary research and should not be considered binding in any way. If required, actual mitigation options and costs must be further reviewed through Facilities Studies with the appropriate Transmission Owner(s). There were no constraints identified in the Flowgate impact analysis for granting service for the MPC02100 TSRs.

5.3.1 Flowgate 6330 Impact The monitored element for Flowgate 6330 (JAMBUFCENMAN) is the Jamestown – Buffalo 345 kV line. The comments provided in Section 4.3.1 apply to Flowgate 6330 as well. Therefore, this Flowgate is not a constraint to service.

5.3.2 Flowgate 6322 Impact The monitored element for Flowgate 6322 (CENMANJAMBIS) is the Roughrider – Mandan 230 kV line. This line’s capacity will be upgraded to 703 MVA (existing rating is 614 MVA) by the MPC02100 project as part of its interconnection requirements7. The flowgate was not identified in the OASIS Automation Tool for the 18 months following the MPC02100 PTP TSR queue date. Therefore, beginning 18 months after the MPC02100 PTP TSR queue date, the TSR will be limited if the Roughrider – Mandan 230 kV line upgrade has not been completed.

7 See “MPC02100 Interconnection System Impact Study Addendum”, 12/29/2015


Flowgate Type RatingPre-TSR MW

FlowPost-TSR MW Flow

TDF % Notes

5028:DICBELANTCHA Cont 224.0 228.4 233.2 4.8%Parallel circuit has been

built for contingent element

6330:JAMBUFCENMAN Cont 639.3 662.8 685.2 22.4%Uprate by prior queued J262/J263 adequate




TDF % Notes

6330:JAMBUFCENMAN Cont 639.3 666.0 690.8 24.8%Uprate by prior queued J262/J263 adequate




TDF % Notes

2336:BTHPALCOOPAL Cont 789.4 852.6 858.6 6.0%MISO flowgate (METC),

mitigation not required

6322:CENMANJAMBIS Cont 590.1 545.4 594.2 48.8%Upgrade for

interconnection adequate to cover delivery impacts

2014 Summer Peak

2018 Summer Peak


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5.3.3 Flowgate 5028 Impact The contingent element for Flowgate 5028 (DICBELANTCHA) is the Antelope Valley – Charlie Creek 345 kV line. In 2015, a second Antelope Valley – Charlie Creek 345 kV line was energized as part of Basin Electric Power Cooperative’s Antelope Valley to Neset 345 kV transmission project, as well a 345 kV line from Charlie Creek to a new Judson substation. These lines were added to the 2014 summer peak model and Flowgate 5028 was manually simulated. Loading on the Dickinson – Belfield 230 kV line was reduced to 94 MVA, well below the 224 MVA Flowgate rating. Therefore, this is not a constraint.

6 Summary of Results The following constraints to granting firm service were identified and must be mitigated prior to granting the TSRs. All constraints have been previously identified for upgrade by a prior queued project or in the MPC02100 Interconnection System Impact Study. Therefore, no Facility Studies are required as a result of this analysis.

• MPC02100 Network TSR (#82005059) o No constraints

• MPC02100 Point-to-Point TSR to MISO border (#82005031) o This TSR only grants service across the Minnkota Transmission system to the MISO

border. o Service will be limited by loading on the Jamestown – Buffalo 345 kV line and

corresponding Flowgate 6330 (JAMBUFCENMAN) only if the MISO GIR J262/J263 goes in service without having completed its required upgrade on this line.

o Service will be limited by Flowgate 6322 CENMANJAMBIS starting 6/18/2017 if MPC02100 has not completed the upgrade of the Roughrider – Mandan 230 kV line which is required for interconnection service.

Appendix A

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Appendix A – Documentation of TSR Modeling

A.1 Minnkota Power Cooperative TSR Queue Assign Ref MW POR POD Service Status Start Time Stop Time Queued

Time 81617403 34 WAUE MPC MPC YEARLY F NETWORK DES CONFIRMED 9/1/2015 1/1/2059 1/31/1956

81607397 250 MPC MPC MPC YEARLY F NETWORK DES CONFIRMED 8/31/2015 12/31/2058 11/20/1970

81607398 250 MPC MPC MPC YEARLY FIRM PTP CONFIRMED 8/31/2015 12/31/2058 11/20/1970





81617404 51 WAUE MPC MPC YEARLY F NETWORK DES CONFIRMED 9/1/2015 1/1/2021 10/22/1996













81607447 69 MPC OTP MPC YEARLY FIRM PTP CONFIRMED 8/31/2015 12/31/2059 7/21/2009












81617405 20 MPC WAUE MPC YEARLY FIRM PTP CONFIRMED 9/1/2015 1/1/2016 7/26/2012




81617409 70 OTP GRE MPC YEARLY FIRM PTP CONFIRMED 8/31/2015 12/31/2044 12/19/2014

81617410 100 MPC GRE MPC YEARLY FIRM PTP CONFIRMED 3/1/2019 6/1/2022 3/4/2015

81607456 200 MPC NSP MPC YEARLY FIRM PTP STUDY 7/31/2016 7/31/2021 3/31/2015

Appendix A

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A.2 Neighboring Transmission Service Provider TSR Queues Assign Ref TP MW POR POD Service Status Start Time Stop Time Queued

Time 75045829 MISO 146 OTP OTP YEARLY FIRM

NETWORK DES CONFIRMED 2002-01-31 2021-12-31 2002-05-23

75045838 MISO 58 OTP OTP YEARLY FIRM NETWORK DES CONFIRMED 2002-01-31 2021-12-31 2002-05-23




941998 WAPA 100 WAUE WAUE YEARLY FIRM NETWORK CONFIRMED 2006-10-01 2015-01-01 2005-01-24


76274372 MISO 148 GRE OTP GFA OPTION A CONFIRMED 2005-03-31 2035-12-31 2005-03-13

76274389 MISO 90 GRE NSP GFA OPTION A CONFIRMED 2005-03-31 2035-12-31 2005-03-13

76274435 MISO 40 GRE GRE GFA OPTION A CONFIRMED 2005-03-31 2035-12-31 2005-03-13

76274436 MISO 58 GRE OTP GFA OPTION A CONFIRMED 2005-03-31 2035-12-31 2005-03-13

76293659 MISO 55 GRE NSP YEARLY FIRM NETWORK DES CONFIRMED 2006-05-31 2026-05-31 2005-03-29












76703672 MISO 250 MHEB-MISO MP YEARLY FIRM







76733237 MISO 10 OTP NSP YEARLY FIRM NETWORK DES CONFIRMED 2009-11-30 2019-11-30 2009-01-26

76733241 MISO 30 OTP ALTW YEARLY FIRM NETWORK DES CONFIRMED 2009-11-30 2019-11-30 2009-01-26

76733730 MISO 30 MDU MDU YEARLY FIRM NETWORK DES CONFIRMED 2009-03-31 2039-12-31 2009-01-28

73868626 WAPA 15 MPCN WAUE YEARLY FIRM NETWORK CONFIRMED 2010-02-15 2020-02-15 2010-02-12

Appendix A

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Assign Ref TP MW POR POD Service Status Start Time Stop Time Queued

Time 76827539 MISO 99 MDU OTP YEARLY FIRM


Error! Hyperlink reference not valid.

WAPA

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WAUE WAUE YEARLY FIRM NETWORK CONFIRMED 2013-01-01 2038-01-01 2011-09-27


WAPA

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WAPA

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WAPA

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79258361 MISO 133 MHEB-MISO MP YEARLY FIRM


79258364 MISO 200 MHEB-MISO WPS YEARLY FIRM


Appendix A

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Assign Ref TP MW POR POD Service Status Start Time Stop Time Queued

Time 79557019 MISO 108 MDU MDU YEARLY FIRM



PTP CONFIRMED 2030-05-31 2035-05-31 2014-08-25


PTP CONFIRMED 2030-05-31 2035-05-31 2014-08-25


PTP CONFIRMED 2030-05-31 2035-05-31 2014-08-25




80705210 MISO 36 MDU PJM YEARLY FIRM PTP CONFIRMED 2016-05-31 2020-05-31 2015-01-14

80705237 MISO 72 MDU PJM YEARLY FIRM PTP STUDY 2016-05-31 2020-05-31 2015-01-14

80732911 MISO 72 MDU PJM YEARLY FIRM PTP STUDY 2016-05-31 2020-05-31 2015-01-21

Appendix B

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Appendix B –Contingency Screen Analysis Results

B.1 DC Contingency Screen Analysis Results See attached file

B.2 AC Contingency Screen Analysis Results See attached file

MPC02100 TSR System Impact Study for MPC Network … TSR System Impact Study for MPC Network Service...

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