Transmission and Interconnection - Wisconsin

Highland Wind Farm February 2012

APPENDIX C

Transmission and Interconnection

Figure 2.4‐2 One‐line Drawing of Interconnection (revised size to

11 x 17 February 2012)

MISO Queue Information – Public

J177 – MISO Feasibility Study


J177 – SPA System Impact Study Final Report (added February

2012)

PSC REF#:160358Public Service Commission of Wisconsin

RECEIVED: 02/28/12, 1:21:59 PM

EXHIBIT 1Part 5 of 432535-CE-1001/17/2013 (aff)

ATTACHMENT 6BPROPOSED HIGHLAND

WINDFARMGENERATING STATION.

161kV ONELINE9-20-10

34.5 KVCIRCUITBREAKER

NORDEX N100 2500 KWWIND TURBINE

2750 KVA34.5KV/660V

DELTA/WYE UNGROUNDEDTRANSFORMER

NORDEX N100 2500 KWWIND TURBINETURBINE #1 TURBINE #10

2750 KVA34.5KV/660V



2750 KVA34.5KV/660V



2750 KVA34.5KV/660V



2750 KVA34.5KV/660V



2750 KVA34.5KV/660V



2750 KVA34.5KV/660V



2750 KVA34.5KV/660V





M

POINT OF INTERCONNECT

TRANSMISSIONSYSTEM

PROPOSED HIGHLANDWINDFARM GENERATING

STATION161/34.5kV

66/88/110 MVA

161kV GND-WYE/13.08kV DELTATERTIARY/34.5kV

GND-WYE

8%Z 161-34.5kV30%Z 161-13.8kV30%Z 34.5-13.8kV10 MVA TERTIARY

To Xcel Energy 161kVPine Lake Substation

To Xcel Energy 161kVApple RiverSubstation

Figure 2.4-2

Highland Wind Farm December 2011

MISO Queue Information (Public)

MISO Queue Information (Public)

Highland Wind Farm, LLC ‐ St. Croix County, Wisconsin

MISO Project Num J177 J221

MISO Queue Date 11/15/2010 8/22/2011

Project Transmission Owner (TO) XEL (NSP) XEL (NSP)

County St. Croix St. Croix

State WI WI

Study Cycle SPA‐2011‐NOV FES‐2011‐SEP

Group SE MN IA

Interconnection Service Type ER ER

Point of Interconnection Pine Lake ‐ Apple River 161kV Pine Lake ‐ Apple River 161 kV

Max Summer Output 97.5 5

Max Winter Output 97.5 5

In Service Date 6/1/2012 12/1/2012

Type of Generating Facility WT

Fuel Type Wind Wind

Study Status SPA ‐ System Impact Study DPP ‐ Parked

Overall Project Status Active Active

Feasibility Study Report

https://www.misoenergy.org/_la

youts/MISO/ECM/Redirect.aspx?

ID=22158

https://www.midwestiso.org/_la

youts/MISO/ECM/Redirect.aspx?

ID=116752

Impact Study Report

Facility Study Report

Optional Study Report

Status after IA

Date of Inactive or Done Status:

MISO Project Number J177Point of Interconnection Pine Lake ‐ Apple River 161kV

Summer Net Output (MW) 97.5Result SPA

Summer Off Peak

Monitored Element Contingency DF (%) Rating (MVA)

Overload (%)

FCITC (MW)

Oakgrove ‐ Galesburg 161 kV ckt 1 Cordova B ‐ Cordova 345 kV ckt 1 5.1 208 176.4 ‐3037Zion ‐ Pleasant Prairie 345 kV ckt 1 Base Case 16.3 924.3 127 ‐1427Edgewater ‐ Cedar Sauk 345 kV ckt 1 Contingency: ATC_C5‐9C 7.8 620.3 117.9 ‐1323Electric Junction ‐ Nelson 345 kV ckt 1 Byron ‐ Lee Co 345 kV ckt 1 12.6 1209.3 112.9 ‐1133Point Beach ‐ SEC 345 kV ckt 1 Edgewater ‐ Cedar Sauk 345 kV ckt 1 7.5 463.6 117.4 ‐980Cypress ‐ Forest Jct 345 kV ckt 1 Contingency: ATC_C5‐9C 10.5 463.6 122.2 ‐886Granville 345/138 kV ckt 1 Granville 2 ‐ Granville 1 345 kV ckt 1 6.5 454.1 112.7 ‐788Sigel ‐ Arpin 138 kV ckt 1 Arpin ‐ Rocky Run 345 kV ckt 1 8.1 272.6 113.9 ‐371Tiffin 345/161 kV ckt 1 Hills ‐ Tiffin 161 kV ckt 1 5.4 336 103.8 ‐144Arpin 345/138 kV ckt 1 Arpin ‐ Rocky Run 345 kV ckt 1 8.8 361.9 102.7 ‐12.5

Summer Peak


Overload (%)

FCITC (MW)

Zion ‐ Pleasant Prairie 345 kV ckt 1 Cherry Valley ‐ Silver Lake 345 kV ckt 1 17.8 1015.5 114.4 ‐800Cypress ‐ Forest Jct 345 kV ckt 1 Contingency: ATC_C5‐9C 10.6 463.6 116.3 ‐696Zion ‐ Pleasant Prairie 345 kV ckt 1 Base Case 16.5 924.3 108.7 ‐471Electric Junction ‐ Nelson 345 kV ckt 1 Byron ‐ Lee Co 345 kV ckt 1 12.5 1209.3 103.6 ‐331Sigel ‐ Arpin 138 kV ckt 1 Arpin ‐ Rocky Run 345 kV ckt 1 8.1 272.6 110.1 ‐319Arpin 345/138 kV ckt 1 Arpin ‐ Rocky Run 345 kV ckt 1 8.8 361.9 107 ‐268

Contingency: ATC_C5‐9C Granville ‐ SEC 345 kV ckt 1Plymouth ‐ Howard Grove 138 kV ckt 1Plymouth ‐ Holland 138 kv ckt 1

County St. CroixState WI

Control Area DPCFuel Wind

*Constraints reported in the feasibility study have a distribution factor above 5%. Page 1 of 1 12/10/2010

MISO Project Number J221Point of Interconnection Pine Lake ‐ Apple River 161 kV

Summer Net Output (MW) 5Result DPP

Summer Off Peak


Overload (%)

FCITC (MW)

Zion ‐ Pleasant Prairie 345 kV ckt 1 Zion ‐ Aracdian 345 kV ckt 1 21.4 1069 115.9 ‐789.9

Summer Peak


Overload (%)

FCITC (MW)

n/a n/a

Fuel Wind

County St. CroixState WI

Control Area ATC

*Constraints reported in the feasibility study have a distribution factor above 5%. N/A indicates no constriants have been found based on the scope of the feasilbity screening. Page 1 of 1 September 16, 2011

Highland Wind Farm February 2012

J177 – SPA System Impact Study

Final Report (added February 2012)

Midwest Independent P.O. Box 4202 1125 Energy Park Drive www.midwestmarket.org Transmission System Operator, Inc Carmel, Indiana 46082-4202 St. Paul, Minnesota 55108 317-249-5400

Generator Interconnection System Planning and Analysis (SPA) System Impact study

SEMNIA November 2011 Study Group Final Report

February 13, 2012

MISO

720 City Center Drive Carmel

Indiana - 46032 http://www.misoenergy.org

SPA November 2011 SEMNIA Group Study

2

TABLE OF CONTENTS

LIST OF TABLES ------------------------------------------------------------------------------------------ 4 LIST OF FIGURES ---------------------------------------------------------------------------------------- 5 1 EXECUTIVE SUMMARY -------------------------------------------------------------------------- 6 1.1 SEMNIA PROJECTS --------------------------------------------------------------------------------- 6 1.2 TRANSMISSION UPGRADE COST AND ALLOCATION --------------------------------------------- 6 1.3 NETWORK UPGRADES ------------------------------------------------------------------------------- 7

1.3.1 Shared Network Upgrades----------------------------------------------------------------- 7 1.4 STUDY OVERVIEW --------------------------------------------------------------------------------- 10

1.4.1 Steady State Analyses -------------------------------------------------------------------- 11 1.4.2 Stability Analysis --------------------------------------------------------------------------- 11 1.4.3 Short Circuit Analysis --------------------------------------------------------------------- 11

1.5 NEXT STEPS ---------------------------------------------------------------------------------------- 11

2 INTRODUCTION ---------------------------------------------------------------------------------- 12 3 STEADY STATE ANALYSIS ------------------------------------------------------------------- 14 3.1 CRITERIA METHODOLOGY AND ASSUMPTIONS ------------------------------------------------ 14

3.1.1 Monitored Elements ----------------------------------------------------------------------- 14 3.1.2 Contingencies ------------------------------------------------------------------------------- 15

3.2 MODEL DEVELOPMENT ---------------------------------------------------------------------------- 15 3.3 SUMMER OFF-PEAK ANALYSIS ------------------------------------------------------------------- 17

3.3.1 Thermal Analysis --------------------------------------------------------------------------- 17 3.3.2 Voltage Analysis ---------------------------------------------------------------------------- 17

3.4 SUMMER PEAK ANALYSIS ------------------------------------------------------------------------- 17 3.4.1 Thermal Analysis --------------------------------------------------------------------------- 17 3.4.2 Voltage Analysis ---------------------------------------------------------------------------- 18

3.5 DELIVERABILITY ANALYSIS ------------------------------------------------------------------------ 18 3.5.1 Study Methodology ------------------------------------------------------------------------ 19 3.5.2 Modeling Details ---------------------------------------------------------------------------- 19 3.5.3 Results ---------------------------------------------------------------------------------------- 19

3.6 N-2 CONTINGENCY ANALYSIS -------------------------------------------------------------------- 20 3.6.1 Introduction ---------------------------------------------------------------------------------- 20

4 STABILITY ANALYSIS -------------------------------------------------------------------------- 21 4.1 INTRODUCTION ------------------------------------------------------------------------------------- 21 4.2 MODEL BUILDING ---------------------------------------------------------------------------------- 21 4.3 DYNAMIC MODEL ----------------------------------------------------------------------------------- 23 4.4 DISTURBANCES STUDIED ------------------------------------------------------------------------- 24 4.5 RESULTS -------------------------------------------------------------------------------------------- 27

5 SHORT CIRCUIT ---------------------------------------------------------------------------------- 28 6 NETWORK UPGRADES AND COST ALLOCATION ----------------------------------- 29 6.1 NETWORK UPGRADES ----------------------------------------------------------------------------- 29


3

6.2 SHARED NETWORK UPGRADES ------------------------------------------------------------------ 29 6.3 COST ALLOCATION --------------------------------------------------------------------------------- 32

7 CONCLUSIONS ----------------------------------------------------------------------------------- 33 8 APPENDICES -------------------------------------------------------------------------------------- 34 8.1 MODELING DOCUMENTATION --------------------------------------------------------------------- 34

8.1.1 Starting Model ------------------------------------------------------------------------------ 34 8.1.2 Generation Interconnection Projects -------------------------------------------------- 37 8.1.3 Topology Changes ------------------------------------------------------------------------- 41

9 SUMMER OFF-PEAK CONSTRAINTS ----------------------------------------------------- 43 10 SHARED NETWORK UPGRADE COST ALLOCATION ------------------------------- 44


4

LIST OF TABLES Table 1.1 – SEMNIA Group Generation Interconnection Requests Evaluated ................ 6 Table 1.2 – Cost Allocation Summary ............................................................................. 6 Table 1.3 – SPA 2011 SEMNIA Local Network Upgrades .............................................. 7 Table 1.4 – SPA 2011 SEMNIA Interconnection Facilities .............................................. 7 Table 1.5 – SPA 2008 Phase 3 Regional Upgrade Plan ................................................. 8 Table 1.6 – Shared Network Upgrade Cost Allocation .................................................... 9 Table 2.1 – 2011 SEMNIA Generation Interconnection Requests Evaluated ................ 12 Table 3.1 – Monitored Area ........................................................................................... 14 Table 3.2 – Transmission Owner Voltage Criteria ......................................................... 14 Table 3.3 – SPA 2011 SEMNIA Generation Interconnection Requests Evaluated ....... 16 Table 3.4 – SEMNIA Dispatch Assumptions ................................................................. 17 Table 3.5 – SPA 2011 SEMNIA Thermal Analysis Results ........................................... 17 Table 3.6 – Summer Off-peak Mitigation Included ........................................................ 18 Table 3.7 – Summer Peak MW Output Studied for November 2011 generation ........... 18 Table 3.8 – Generators Studied for Delieverability ........................................................ 18 Table 3.9 – G991 Deliverability Constraints .................................................................. 19 Table 3.10 – Generators Studied Deliverable Amounts ................................................ 19 Table 3.11 – SPA 2011 SEMNIA N-2 Analysis Results ................................................. 20 Table 4.1 – SPA November 2011 Minnesota Group Projects ....................................... 21 Table 4.2 – Regional Faults .......................................................................................... 24 Table 4.3 – 765 kV Faults ............................................................................................. 26 Table 4.4 – SEMNIA group Local Faults ....................................................................... 26 Table 6.1 – SEMNIA 2011 ERIS Network Upgrades ..................................................... 29 Table 6.2 – SEMNIA 2011 Delieverabily Network Upgrades ......................................... 29 Table 6.3 – Regional Upgrade Plan .............................................................................. 30 Table 6.4 – Shared Network Upgrade Cost Allocation .................................................. 31 Table 6.5 – Cost Allocation Summary ........................................................................... 32 Table 7.1 – Cost Allocation Summary ........................................................................... 33 Table 8.1 – Regional 765kV Summarized Plan ............................................................. 34 Table 8.2 – MTEP Appendix B Projects ........................................................................ 35 Table 8.3 – MVP Projects Added to the Model .............................................................. 37 Table 8.4 – SPA 2011 MN Study Projects (SPA Cycle 4) ............................................. 37 Table 8.5 – SPA 2011 MN Withdrawn Projects (SPA Cycle 4) ..................................... 38 Table 8.6 – Withdrawn or Parked for One Year High Queue Projects .......................... 38 Table 8.7 – Generation Added to the Model .................................................................. 40 Table 9.1 – Summer Off Peak Constraints before Mitigation ........................................ 43 Table 10.1 – SPA 2011 SEMNIA Shared Network Upgrade Cost Allocation ................ 44 Table 10.2 – SPA 2011 SEMNIA Initial Drivers of Share Network Upgrade .................. 45


5

LIST OF FIGURES Figure 1.1 – Phase 3 Regional Transmission Plan ......................................................... 9 Figure 2.1 – Map of SEMNIA 2011 projects .................................................................. 12 Figure 4.1 – Single-Machine Equivalent Power Flow Presentation for a WPP .............. 22 Figure 6.1 – Phase 3 Regional Transmission Plan ....................................................... 31


6

1 EXECUTIVE SUMMARY The Southeast Minnesota and Northern Iowa (SEMNIA) study analyzes the impact of proposed wind generation. The total generation for the System Planning and Analysis (SPA) SEMNIA study is 522.5 MW. This report documents the study work performed for the SEMNIA study; the purpose was to evaluate the steady state, stability, and short circuit impacts, determine the cause of any system or reliability limitations, and provide preliminary transmission system requirements for the reliable interconnection of the requests proposed in the Xcel (NSP), ITC Midwest (ALTW) and Southwest Minnesota Municaple Agency (SMMPA) control areas, shown in Table 1.1. The SPA 2011 SEMNIA study utilizes transmission improvements previously identified in the SPA 2008 Phase 3 study which are required to accommodate SPA generation in MISO-west area (MN, Dakotas, and IA). A 765 kV regional plan as shown in Figure 1.1 has been proposed to accommodate SPA generation in the MISO-west area. This report documents the results of the study work performed that included steady state, stability and short circuit analyses.

1.1 SEMNIA Projects Table 1.1 lists SEMNIA projects; SPA generation which has been studied previously is documented in the Appendix, Section 8.1.

Table 1.1 – SEMNIA Group Generation Interconnection Requests Evaluated

MISO Project County State Service

Type Transmission

Owner Point of Interconnection Size (MW)

Fuel Type

C771 Howard IA NR ALTW Mitchell County 345kV 200 Wind G991 Fillmore MN NR ALTW Lansing - Harmony 161kV 200 Wind J177 St. Croix WI ER XEL (NSP) Pine Lake - Apple River 161kV 97.5 Wind J216 Mower MN NR SMMPA Austin Northeast 69 kV Substation 25 Wind

1.2 Transmission Upgrade Cost and Allocation The network upgrades cost for the SEMNIA projects is provided in Table 1.2 below. These costs include network upgrades, interconnection facilities, and previously identified network upgrades that the SEMNIA group will be responsible in sharing costs.

Table 1.2 – Cost Allocation Summary

Project Num

ERIS Network Upgrades ($M)

NRIS Network Upgrades

($M) Interconnection Facilities

($M)

Shared Network Upgrade

($M)

Estimated Cost ($M)

$/MW ($M) Thermal

($M)

Reactive Support (Steady

state and dynamic)

($M)

Short-circuit($M)

Deliverability ($M)

G771 0 0 0 0 5.00 40.23 45.23 0.23

G991 15.00 0 0 4.50 5.00 16.46 40.96 0.21

J177 0 0 0 0 5.00 0 5.00 0.05

J216 0 0 0 0 5.00 0 5.00 0.20 Total ($M) 15.00 0 0 4.50 20.00 56.69 96.19 Average

0.17


7

The cost is allocated to individual generators based on the MW impact from each project on the constrained facilities. The cost share of each project for the identified network upgrades is calculated considering only study projects in this group are sharing the cost of new transmission projects.

1.3 Network Upgrades Network upgrades were identified via detailed AC analysis. These upgrades are required to mitigate local bottlenecks for all generation projects in the SEMNIA group. A planning level estimate for local upgrades is approximately $15 million, Table 1.3.

Table 1.3 – SPA 2011 SEMNIA Local Network Upgrades

Constraint Upgrade Estimated Cost ($M)

Projects Responsible

Lansing - Genoa 161kV Rebuild Lansing – Genoa 161kV 15.00 G991

Table 1.4 lists the Transmission Owner Interconnection Facilities required at the point of interconnection of study generator.

Table 1.4 – SPA 2011 SEMNIA Interconnection Facilities

Project MW Service Type Point of interconnection Interconnection Facilities required

Interconnection

Facilities ($M)

G771 200 NR 345kV line near Afton or Howard Township 3 Breaker Ring Bus 5.00 G991 200 NR Alliant 161 kV 3 Breaker Ring Bus 5.00 J177 97.5 ER Pine Lake - Apple River 161kV 3 Breaker Ring Bus 5.00 J216 25 NR Austin Northeast 69 kV Substation 3 Breaker Ring Bus 5.00

1.3.1 Shared Network Upgrades The SPA November 2008 Phase 3 Regional Plan was a base case assumption for the SPA November 2011 study. The original Regional Transmission Upgrades were identified via linear power flow analysis and were required for the integration of generation interconnection projects in the SPA 2008 Phase 3 study as well as prior queued generation projects in the SPA November 2008, November 2009 and November 2010 studies. These upgrades are required to unlock the regional bottlenecks for all generation projects prior queued to the SPA 2011 SEMNIA cycle. The proposed regional plan is shown in Figure 1.1 and a planning level cost estimate for Regional Transmission Upgrades is approximately $10 billion as reported in Table 1.5. The full details of the Phase 3 regional plan are available in the Phase 3 SEMNIA study1.

1 Phase 3 SEMNIA SPA Study: https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID=101460

alleviated sconstrainton impactsMW projects All

alleviated sconstrainton impact MW A Proj. NU ofCost NU ofportion A Proj.


8

Table 1.5 – SPA 2008 Phase 3 Regional Upgrade Plan

Regional Plan Mileage Total

Estimated Cost ($M) 2

Big Stone-Brookings Co 765 kV 63 336.4

Big Stone-Canby 345 kV 51 100.9

Canby-Hazel 345 kV 44 79.2

Hazel-Panther 345 kV 39 70.2

Panther-McLeod 345 kV 27 71.8

McLeod-Blue Lake 345 kV 47 84.6

Split Rock-Brookings Co. 765 kV 60 347.9

Brookings Co - Helena 765 kV 149 603.4

Helena-Mitchell Co 765 kV 113 533.4

Mitchell Co-Hazleton 765 kV 78 387.5

Hazleton-Hills 765 kV 77 384.3

Split Rock-Lakefield 765 kV 77 407.4

Lakefield-Mitchell Co 765 kV 128 417.3

Split Rock-Raun 765 kV 105 473.9

Raun-New Station 765 kV 71 252.3

Lakefield -New Station 765 kV 140 448

Brookings Co-Lakefield 765 kV 115 402.5

New Station-Grimes 765 kV 107 480.3

Grimes-Hills 765 kV 118 514.9

Mitchell Co-Genoa 765 kV 73 424.9

GRE Pleasant Valley-Preston 345 kV 37 72

Preston-Genoa 345 kV 66 144.6

Preston-H028 Tap 345 kV 37 77.9

Genoa-North La Crosse 345 kV 29 66.8

Genoa-North Monroe 765 kV 132 690.3

North Monroe-Byron 765 kV 58 370.7

Byron-Plano 765 kV 77 226.8

Byron-Charter Grove 345 kV 40 95.8

Charter Grove-Wayne 345 kV 14 35.3

Hills-Kewanee 765 kV 117 497

Kewanee-Pontiac 765 kV 88 384.9

Kewanee-Collins 345 kV 66 104.9

Pontiac-Greentown 765 kV 169 485.8

Hills-Barstow 345 kV 93 164.1

Barstow-Kewanee 345 kV 23 34.5

2 Total Estimated Costs include substation, transformer, and line upgrade costs.


9



Total $10,2733

Note – Critical Energy Infrastructure Information has been redacted

Figure 1.1 – Phase 3 Regional Transmission Plan

In addition to the assessment of Shared Network Upgrades4 for the Phase 3 Regional Transmission Plan any network upgrades assigned to projects included in the study model were considered. Table 1.6 summarizes the cost allocation for SEMNIA projects on previously identified network upgrades.

Table 1.6 – Shared Network Upgrade Cost Allocation

Upgrade Rating(MVA)

Type of Upgrade

Facility Cost ($M)

G771 ($M)

G991 ($M)

J177 ($M)

J216 ($M)

Mitchell County - Hazelton 765 ckt 1 5300 New

Equipment 249.60 5.05

Genoa 345/161 Transformer 336 New

Equipment 11.80

3.37

Genoa - North Monroe 765 ckt1 5300 New

Equipment 529.20 7.62 7.64

Byron 765 - North Monroe 765kv ckt1 5300 New

Equipment 232.80 3.30 3.41

Adams 345/161 Transformer 500 New

Equipment 11.40

1.13

3 Slight modification to the Phase 3 cost due to approval of MTEP Appendix B projects moving to Appendix A. 4 The Generation Interconnection BPM 015 provides the details of the SNU analysis: https://www.misoenergy.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesManuals.aspx


10

Upgrade Rating(MVA)

Type of Upgrade

Facility Cost ($M)

G771 ($M)

G991 ($M)

J177 ($M)

J216 ($M)

Adams - South Adams 161kV ckt1 473.1 Reconductor 0.35 0.05

Beaver Creek - Harmony 161kV ckt1 249.6 Reconductor 2.91 0.86

Mitchell County 765/345kV Transformer 1 2767.5 New

Equipment 56.4 6.35


Equipment 56.4 6.35

Mitchell County Substation 345/765

Substation New


Total Estimated Cost: 40.23 16.46 0.00 0.00

1.4 Study Overview The study was performed by MISO. An ad hoc group was formed to participate in the study. The ad hoc group reviewed the study results and provided feedback on several issues including but not limited to the equipment rating verification, suggestions for Network Upgrades, physical limitations at the existing substations, ROW availability etc. The following companies were invited to participate in the study:

Xcel Energy (NSP) Minnesota Power (MP) Southern Minnesota Municipal Power Agency (SMMPA) Great River Energy (GRE) Otter Tail Power (OTP) ITC Midwest (ALTW) Mid American Energy (MEC) Nebraska Public Power District (NPPD) Western Area Power Administrator (WAPA) Manitoba Hydro (MHEB) Dairyland Power Cooperative (DPC) American Transmission Company (ATC) Minnkota Power (MPC) Basin Electric Power Cooperative (BEPC) Missouri River Energy Services (MRES) Montana – Dakota Utilities (MDU) American Electric Power (AEP) Michigan Electric Coordinated Systems (MECS) Ameren (AMRN) Commonwealth (CE) Southern Minnesota Municipal Power Agency (SMP) Northern Indiana Public Service Company (NIPS) Study project Generation Interconnection Customers

The system impact study included the following evaluations:

A thermal analysis to identify the limiting conditions at increasing levels of generation for NERC category A, B, and selected C events.

A dynamic stability analysis A short-circuit analysis Deliverability analysis for Network Resource Interconnection Service (NRIS) requests Determination of transmission system improvements, including new facilities and upgrades to the

existing infrastructure Cost allocation of transmission improvements by project


11

1.4.1 Steady State Analyses The starting models used for the thermal analyses were developed from the MTEP09 2019 model used for SPA 2008 SEMNIA Phase 3 study. This model was updated for the SPA 2011 SEMNIA as document is Section 8.1 of the Appendix.

1.4.1.1 Summer Off-peak Injection constraints noted in Table 3.5 were identified from the thermal, summer off-peak analyses. The only injection constraint identified is the Lansing to Genoa 161 kV line impacted by project G991. The cost to upgrade this facility is $15 million.

1.4.1.2 Summer Peak and Deliverability Analysis No constraints were identified in the summer peak analysis contingent upon the summer off-peak ERIS analysis upgrades being in place. One deliverability constraint was identified for G991, Harmony to G991 tap. A desired rating of 446 MVA is desired. G991 is deliverable to 68 MW (requested 200 MW). G991 can choose either to mitigate the constraint for a cost of $4.5 million or have limited deliverability to 68 MW.

1.4.2 Stability Analysis The stability analysis performed in this study was based on the MTEP 10 2015 shoulder model previously used for the SPA 2008 SEMNIA Phase 3 stability study. All the transmission upgrades that are identified in the summer off peak analysis are included in the case. Additional stability upgrades are not required for the SPA 2011 SEMNIA generators conditional upon ERIS Mitigation already in place.

1.4.3 Short Circuit Analysis There are no changes in transmission assumptions for the SPA November 2011 SEMNIA study when compared to Phase 3 study. As such there is no change in the short circuit analysis results. A limited scope Short Circuit Analysis was performed in Phase 3 SEMNIA study to get an indication for need of any breaker replacements. The short circuit current values for both single line to ground and three phase faults appear to be below the circuit breaker interrupting values. These results could be evaluated further in DPP if required.

1.5 Next Steps Upon completion of this system impact study in the SPA phase, the interconnection requests will proceed as follows under the generator interconnection queue procedures:

• MISO will request M2 milestones and D3 deposits for each project. Projects need to meet these requirements before they can proceed to the Definitive Planning Phase (DPP).

– Next DPP cycle begins March 12th, 2012 – Deadline to submit M2 milestones and D3 deposit is February 24, 2012

• Customers may choose to “park” and defer meeting M2 milestones by one DPP cycle • Failure to meet the 2nd DPP deadline would require funding a new Feasibility Study ($5,000) or

the project will remain in parked status – Projects have 1 year from the date of becoming eligible for their 1st DPP study to proceed

or they will be considered withdrawn – Second DPP cycle begins July 23rd, 2012 – Deadline to submit milestones and deposits is July 9th, 2012

• Study Calendar is available on the MISO website – http://www.misoenergy.org/Library/Repository/Study/Generator%20Interconnection/Gene

rator%20Interconnection%20Study%20Calendar.pdf • The details of the DPP process, including milestones/deposit requirements, can be obtained from

the MISO Generator Interconnection Business Practice Manual (BPM5).

5 https://www.midwestiso.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesManuals.aspx


12

2 INTRODUCTION The 2011 Minnesota SPA projects were studied in three groups: Buffalo Ridge, Big Stone, and Southeast MN and Northern IA (SEMNIA) with studies in each group progressing in parallel. This report evaluates the system impacts; determines the cause of any system or reliability limitations and system requirements for the SEMNIA generation interconnection requests. The SEMNIA 2011 generator interconnection requests are shown in Figure 2.1 and Table 2.1 totals 522.5 MW.

Table 2.1 – 2011 SEMNIA Generation Interconnection Requests Evaluated

MISO Project County State Service

Type Transmission

Owner Point of Interconnection Size (MW)

Fuel Type

G771 Howard IA NR ALTW Mitchell County 345kV 200 Wind G991 Fillmore MN NR ALTW Lansing - Harmony 161kV 200 Wind J177 St. Croix WI ER XEL (NSP) Pine Lake - Apple River 161kV 97.5 Wind J216 Mower MN NR SMMPA Austin Northeast 69 kV Substation 25 Wind The geographical location of the request is provided in Figure 2.1, the SEMNIA generation project is located in Southeast Minnesota and Northern Iowa.

Note – Critical Energy Infrastructure Information has been redacted

Figure 2.1 – Map of SEMNIA 2011 projects

An ad hoc group was formed to participate in the study by reviewing the geographical proximity of the generation interconnection requests. The ad hoc reviewed the study results and provided feedback on several issues included but not limited to the equipment rating verification, suggestion for Network


13

Upgrades, physical limitations at existing substation, right of way availability, etc. The following companies were invited to participate:

Xcel Energy (NSP) Minnesota Power (MP) Southern Minnesota Municipal Power Agency (SMMPA) Great River Energy (GRE) Otter Tail Power (OTP) ITC Midwest (ALTW) Mid American Energy (MEC) Nebraska Public Power District (NPPD) Western Area Power Administrator (WAPA) Manitoba Hydro (MHEB) Dairyland Power Cooperative (DPC) American Transmission Company (ATC) Minnkota Power (MPC) Basin Electric Power Cooperative (BEPC) Missouri River Energy Services (MRES) Montana – Dakota Utilities (MDU) American Electric Power (AEP) Michigan Electric Coordinated Systems (MECS) Ameren (AMRN) Commonwealth (CE) Southern Minnesota Municipal Power Agency (SMP) Northern Indiana Public Service Company (NIPS) Study project Generation Interconnection Customers

The ad hoc group was invited to interact in meetings, were included on status update emails, and were contacted for mitigation. The accuracy of the conclusions contained in this study is sensitive to the assumptions made with respect to the generation additions (size, location, modeling data), prior queued generation projects, and other network changes being contemplated outside this study. Any change in these assumptions will affect this study’s conclusion. The system impact study included the following evaluations:

A thermal analysis to identify the limiting conditions at increasing levels of generation for NERC category A, B, and selected C events.

A dynamic stability analysis Determination of transmission system improvements, including new facilities and upgrades to the

existing infrastructure A short-circuit analysis Deliverability of the generation interconnection requests for Network Resource Interconnection

Service (NRIS) Cost allocations by project


14

3 STEADY STATE ANALYSIS 3.1 Criteria Methodology and Assumptions The technical study was performed based on the following objectives, which collectively for the basis of the study scope:

Provide an assessment of the impact the proposed generation capacity addition and associated Network Upgrades will have on the reliability of the Transmission System and Affected Systems

Provide an indication of the ability of the proposed facility to inject its output to the grid Provide a non-binding good faith estimate of the nature, extent, and cost of facilities that may be

required to interconnect and, for NRIS, to deliver the output of the proposed facility the grid

3.1.1 Monitored Elements The impact of the SEMNIA 2011 projects was analyzed for the study region. Generally ratings were analyzed for Rate A for system intact and Rate B for contingency except for specific zones in control area identified with an asterisk in Table 3.1 . All facilities (69kV and above) were monitored for loading greater than 100% of the appropriate rating. The study region included the affected systems in Table 3.1 .

Table 3.1 – Monitored Area

Control Area Name Number Name Number Name Number AEP 205 SIPC 361 OPPD* 645 DEM 208 XEL 600 LES* 650 IPL 216 MP* 608 WAPA* 652

NIPS 217 SMMPA* 613 MDU* 661 CE 222 GRE 615 MH 667

WEC* 295 OTP* 620 DPC 680 CWLD 333 ALTW* 627 ALTE* 694 AMMO 356 MPW 633 WPS* 696 AMIL 357 MEC* 635 MGE* 697

CWLP 360 NPPD* 640 UPPC* 698 *Rate A was analyzed for System Intact and under contingency

Voltages for system intact conditions were analyzed between 0.95 and 1.05. Voltages were generally analyzed under contingency between 0.90 and 1.10 unless specified in Table 3.2 .

Table 3.2 – Transmission Owner Voltage Criteria

Subsystem Buses Low High Subsystem Buses Low High DPC >100 kV 0.90 1.05

OTP 230 kV 0.92 1.10

GRE Hubbard 230 kV 0.92 1.05 115 kV 0.92 1.10

Load Serving 0.92 1.10

MH

500 kV 0.00 1.15

MEC Generator 1.00 1.05 230 kV 0.00 1.09

345 kV 0.94 1.05 220 kV 0.00 1.15

161 kV 0.93 1.05 138 kV 0.00 1.15

MP

230 kV 0.95 1.05 110 kV 0.00 1.10

161 kV 0.95 1.05 Roseau 500 kV 0.00 1.10

138 kV 0.95 1.05 Prairie 115 kV 1.00 1.07

115 kV 0.95 1.05 Prairie 115 kV cap 0.90 1.10

XEL

500 kV 0.93 1.10 Sheyenne 115 kV cap 0.95 1.15

345 kV 0.95 1.10 Running 230 kV cap 0.94 1.10

230 kV 0.95 1.10 Roseau 230 kV cap 0.95 1.15

Generator 0.95 1.10


15

3.1.2 Contingencies Contingency information as supplied by member of the Ad Hoc Study Group and included the following contingency files:

Combined-East-Contingencies-020910_fix.con 19S_RFC-PJM_Study_Cat-B1_031610.con 19S_RFC-PJM_Study_Cat-B2_031610.con 19S_RFC-PJM_Study_Cat-B2_OVEC_031610.con 19S_RFC-PJM_Study_Cat-B3_031610.con 19S_RFC-PJM_Study_Cat-B3_OVEC_031610.con B_Explicit_AMRN_revision_05.25.2010_fix.con B_Explicit_CWLD.con B_Explicit_CWLP_fix.con B_Explicit_SIPC.con B_MultipleTerminalBranch_DEM_V1_fix.con B_MultipleTerminalBranch_HE.con B_MultipleTerminalBranch_IPL.con B_MultipleTerminalBranch_SIGE_fix.con B_SingleBranchTxGens_AMIL.con B_SingleBranchTxGens_AMMO.con B_SingleBranchTxGens_CWLD.con B_SingleBranchTxGens_CWLP.con B_SingleBranchTxGens_DEM.con B_SingleBranchTxGens_HE.con B_SingleBranchTxGens_IPL.con B_SingleBranchTxGens_SIGE.con B_SingleBranchTxGens_SIPC.con B_SingleLineGenTx_IPL.con ipl_nerc_category_b.con CE_singles_345_765_V2.con B1_20090416_ATC_RGOS.con Daks-allmodels-Cat-B_RGOS.con Iowa_category-B_2019 Final_0610_09CD_RGOS_fix.con MN-category-B_2009_6-03-09_pss_CD_RGOS_fix.con XEL_CatB_MUST_0608_09CD_RGOS_fix.con B2-B3_69-345_20090417_ATC_mod_RGOS_updated_fix.con

Blanket statements were also included in the contingency file for all single contingencies 60 kV and above for all monitored areas as shown in Table 3.1 .

3.2 Model Development The SPA 2011 SEMNIA base model building started with the SPA SEMNIA Phase 3 summer off peak model after stakeholder comments received in August 2011 were applied. The detailed changes made to the model are included in Appendix A, some of the more pertinent changes are:

Alexandria 345/115 kV substation correction (purged the two winding transformer in the model and added a three winding transformer (345/115/34.5 kV) with a 50 MVAR switched reactor on the tertiary)

Bison 345/230 kV substation correction (removed 345/230 kV transformers modeled at Bison) Ortonville – G894 – Johnson Jct. 115 kV rating correction, new rating 93 MVA normal and

emergency. The Marshall (MMU) North 7th St. load correction, load was set to 43.0 MW active load and 2.6

MVar reactive load.


16

Moorhead 230/115 kV transformers, Moorhead 115 kV line segments rating update for Fargo to Brook to 119MVA as well as Brook to SE to 127MVA, and Moorehead generation update (generation remains off-line)

Ashtabula generation update dispatched at 641 MW to the MISO footprint Buffalo-Casselton 115 kV line status changed to in-service The 615015 Spiritwood plant is dispatched at 100 MW because it is a baseload The Maple River-Sheyenne 230 kV line rating is updated to 459 MVA normal and 505 MVA

emergency Maple River-Frontier 230 kV line rating is updated to 364 MVA normal and404 MVA emergency Frontier-Wahpeton 230 kV line rating is updated to 364 MVA normal and 364 MVA emergency Harmony to Generation Tap to Lansing 161kV corrected to 200MVA

The models include MTEP09 Appendix A and B transmission projects and generation as well as interconnection projects. Note that projects in MTEP09 Appendix B have not been studied through the MTEP cost-allocation process. If any of these projects in MTEP09 Appendix B fail to move to the Appendix A, these interconnection requests would be reevaluated and such MTEP projects (or appropriate alternatives) may be reclassified as required Network Upgrades for them to be funded according to the existing tariff provisions. The Appendix B projects included in the study are presented in Table 8.2 of the Section 8.1: The full details of the model development are included in Section 8.1 of the Appendix. Generation assumptions: In-service generation, generators with signed GIAs and relevant interconnection queued requests were modeled in the case per the following criteria:

Generation in the study area was modeled at the level of available/requested interconnection service

Baseload generation was dispatched at 100% in both summer off-peak and summer peak scenarios

Peaking generation was modeled as off in summer off-peak and at 100% on in summer peak; Wind generation in the study area was dispatched at 100% in summer off-peak and at 20% in

summer peak. Competing wind generation remote from the study area was modeled at 20% in both summer peak and off-peak scenarios.

Generation Interconnection projects that have completed an Interconnection Agreement or in the Definitive Planning Phase (DPP) through the June 2011 cycle are included as a starting assumption. The respective known upgrades for these prior queued generation interconnection projects are included in the base model. Additionally projects that are active from SPA November 2008, Phase 1, Phase 2 and Phase 3 are also included. The entire list of projects included in the study model is provided in Section 8.1.2 of the Appendix. Approximately 4676.75 MWs of active projects are local to the SPA 2011 SEMNIA area, SPA 2011 SEMNIA geneartion active in the queue and detailed in Table 3.3.

Table 3.3 – SPA 2011 SEMNIA Generation Interconnection Requests Evaluated

MISO Proj No.

County State Service Type

Control Area Point of Interconnection per Model

Max Sum

Output Fuel Type

G771 Howard IA NR ALTW 345kV line near Afton or Howard T hi

200 Wind

G991 Fillmore MN NR ALTW Alliant 161 kV 200 Wind

J177 St. Croix WI ER XEL (NSP) Pine Lake - Apple River 161kV 97.5 Wind

J216 Mower MN NR SMMPA Austin Northeast 69 kV Substation 25 Wind Generation dispatched in the SEMNIA 2011 model was dispatched to the eastern MISO footprint using a tiered merit order dispatch to the eastern control areas (IPL, NIPS, DEM, METC, AMIL). Additionally projects in the SEMNIA group were dispatched at 100% of nameplate, whereas only Network Resources


17

projects in the Big Stone and SEMNIA areas were dispatched at their capacity level (as counted under Module E – generally wind at 20% of nameplate). The DPP cycle designation includes projects that have completed the SPA process and are parked for one DPP cycle or currently in the DPP phase. Table 3.4 provides a summary of the dispatches for each group, a detailed list of the dispatched generators is provided in Section 8.1.2 of the Appendix. The DPP cycle designation includes projects that have completed the SPA process and are parked for one DPP cycle or currently in the DPP phase.

Table 3.4 – SEMNIA Dispatch Assumptions

Group DPP Cycle MW

SPA November

2011, Cycle 4

Total

SEMNIA 4676.75 522.50 5199.25 Big Stone 747.19 10.00 757.19 Buffalo Ridge 215.40 0.00 215.40 Total 5639.34 532.50 6171.84

3.3 Summer off-peak Analysis

3.3.1 Thermal Analysis After dispatching the generation, the constraints in Table 3.5 were identified as injection constraints for the SPA 2011 SEMNIA projects. Table 3.5 only shows the worst contingency condition for system intact and under contingency. Results for the worst five contingencies are provided in Table 9.1in the appendix. Table 3.5 also provides the mitigation considered for the constraint.

Table 3.5 – SPA 2011 SEMNIA Thermal Analysis Results

Limiting Element Type - Owner

Constraint Type

Post Loading

MVA Rating MVA Mitigation Estimated

Cost ($M) Impacting

Project

Lansing - Genoa 161kV LN - DPC N-1 279.8 240 Rebuild Lansing – Genoa

161kV 15.00 G991

3.3.2 Voltage Analysis Voltage limits for the monitored facilities are specified in Table 3-2. These limits are based on the limits outlined in the MAPP Members Reliability Criteria and Study Procedures Manual. The defaults for all buses in the monitored areas are 1.05 per unit (p.u.) for high voltages, 0.95 p.u. for low voltages for system intact conditions and 1.10 p.u. and 0.90 p.u. for post contingency conditions. The voltage study shows no voltage constraints in SEMNIA requiring mitigation.

3.4 Summer peak Analysis

3.4.1 Thermal Analysis The starting model used to build the summer peak case for the November 2011 analysis is the Phase 3 summer peak model which was finalized after multiple stakeholder reviews. This model was created from an MTEP09 2019 summer peak model. Relevant generation projects from the MISO interconnection queue were added to this model to create the November 2011 model. All changes to the model as identified in Section 3.2 have been included in this model.


18

In addition, the mitigation determined through the SPA 2011 Minnesota Area summer off-peak analysis has also been included. Those changes are :

Table 3.6 – Summer Off-peak Mitigation Included Area Mitigation

Buffalo Ridge

New Buffalo Ridge – Yankee 115 kV ckt2 New Yankee - Brookings County Buffalo Ridge 115 kV ckt 3

Increase 345/115kV Brookings Transformers to 672 MVA

SEMNIA Rebuild Lansing – Genoa 302/332 MVA Summer peak analyses are performed with generation modeled at expected output levels. Accordingly, wind generation is modeled at 20% of the requested output. Other fuel types are typically modeled at 100% nameplate. Table 3.7 provides the November 2011 projects that were analyzed for the summer peak analysis and their corresponding output level.

Table 3.7 – Summer Peak MW Output Studied for November 2011 generation MISO Project Service Type Study Region Fuel Type SUPK Dispatch (MW) Pmax

J193 NR Big Stone Wind 10 50 H041 NR Buffalo Ridge Wind 80 400 G771 NR SEMNIA Wind 40 200 G991 NR SEMNIA Wind 40 200 J177 ER SEMNIA Wind 19.5 97.5 J216 NR SEMNIA Wind 5 25

The monitored elements and contingencies tested were the same as per Section 3.1.1 and 3.1.2 with blanket statements for single contingencies 60 kV and above for all monitored areas as shown in Table 3.1. There were no thermal summer peak violations for the SEMNIA study projects.

3.4.2 Voltage Analysis The voltage limits for the monitored facilities are specified in Table 3.2. These limits are based on the limits outlined in the MAPP Members Reliability Criteria and Study Procedures Manual. The defaults for buses in the monitored areas are 1.05 per unit (p.u.) for high voltages, 0.95 p.u. for low voltages for system intact conditions and 1.10 p.u. and 0.90 p.u. for post contingency conditions. The voltage study shows no voltage constraints for the SPA SEMNIA 2011 study scenario.

3.5 Deliverability Analysis Generator interconnection projects have to be deliverable to the MISO network load to be granted Network Resource Interconnection Services (NRIS). The project can choose to accept the level of NRIS available without additional upgrades, or make the required network improvements to obtain NRIS. Deliverability analysis is performed for Network Resource (NR) requests at 100% of the requested output for wind generation interconnection. Table 3.8 provides a list of projects that were analyzed for the deliverability study of SPA SEMNIA 2011 generation interconnection requests.

Table 3.8 – Generators Studied for Delieverability

MISO Project

Service Type

Requested MW

Amount Delieverable

MW Fuel

G771 NR 200 200 Wind G991 NR 200 68 Wind J216 NR 25 25 Wind


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3.5.1 Study Methodology MISO Generator Deliverability Study whitepaper describing the algorithm can be found at https://www.midwestiso.org/Library/Repository/Study/Generator%20Interconnection/Generator%20Deliverability%20Study%20Methodology.pdf

3.5.2 Modeling Details The deliverability analysis started with the MTEP09 2019 summer peak model. Topology of the model used for deliverability is same as that of the summer peak model except that only those projects who have requested Network Resource Interconnection are 100% dispatched in the model. The monitored area and the contingencies were same as that of summer off-peak analysis mentioned in section 3.1.

3.5.3 Results G991 is limisted to 68 MW of deliverability of the 200 MW requested. G991 can choose to mitigate the constraint detailed in Table 3.9.

Table 3.9 – G991 Deliverability Constraints

Limiting Element Type - Owner Constraint Type

Post Loading

MVA Rating MVA Contignecy

Amount Deliverable

(MW) Mitigation

Estimated Cost ($M)

Impacting Project

Harmony - G991 Tap LN - ITC Midwest N-1 315.4 200

Lansing – Genoa 161kV

68 Rebuild

Harmony – Lansing

to 446MVA

4.50 G991

N-0 223.7 200 1606

No constraints were identified in the deliverability analysis for projects G771 and J216. These projects are fully deliverable accoding to Table 3.10.

Table 3.10 – Generators Studied Deliverable Amounts

MISO Project

Service Type

Requested MW

Amount Delieverable

MW Fuel

G771 NR 200 200 Wind G991 NR 200 68 Wind J216 NR 25 25 Wind

6 G991 would be limited to the most deliverable amount, under N-1 scenario of 68 MW.


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3.6 N-2 contingency Analysis

3.6.1 Introduction The purpose of N-2 contingency analysis is to determine transmission system thermal overloads following simultaneous outage of selected double contingencies in the vicinity of the proposed projects. This evaluation is for informational purposes only and therefore mitigation is not proposed. The contingencies considered were from a local outlet perspective of each study project. The details of the N-2 contingency analysis can be found in Table 3.11 with potential limiters highlighted.

Table 3.11 – SPA 2011 SEMNIA N-2 Analysis Results

Limiting Element Post

Loading MVA

RatingMVA

Loading%

Contingency Description G771 G991 J177 J216

Genoa 345/161 kV Transformer

445.2 336.0 132.5 Seneca - Genoa ckt1

Michell County - Genoa 765kV ckt1

<5% 29% 6% <5%

Adams - Mitchel County 345kV ckt1

1527.1 956.0 159.7

Michell County - Helena ckt 1

Michell County - Hayward ckt1

<5% 19% 17% 34%

Austin - T Bp 69kV ckt1

69.7 50.0 139.5 Austin 5 - Autin 1 Austin 5 - Austin 2

<5% <5% <5% 100%

Bloom PR - Boom PR Northeast 69kV ckt1

79.3 50.0 158.7 Austin 5 - Autin 1 Austin 5 - Austin 2

<5% <5% <5% 100%

Adams North - Adams South 161kV ckt1

219.6 205.0 107.1

Adams - Pleasant Valley

Adams - Adams North

<5% <5% <5% 28%

Thermal loading will be evaluated for appropriate Category C contingencies and facilities with loadings of up to 125% or more of their emergency rating will be flagged as a potential loading condition that could lead to uncontrolled cascading outages, for which the operator may not have time to take emergency action. New interconnection requests shall pass the test if no facility is loaded beyond its emergency rating (taking into account appropriate NERC/ERO/Regional criteria) or an operating procedure, including the controlled reduction of generation or load, is available to get the facility under its appropriate rating. Otherwise, upgrades must be identified to alleviate the condition to be further analyzed in DPP.


21

4 Stability Analysis 4.1 Introduction SPA November 2011 Minnesota Group consist of three groups:

SEMNIA – Southeast Minnesota Iowa Group Individual project J193 Buffalo Ridge Group

The Southeast Minnesota Iowa Group is the focus of this study.

4.2 Model Building SPA 2008 November SEMNIA Phase 3 stability final study model (MTEP 10 2015 shoulder model) was used as a starting mode7. A benchmark case was created by removing withdrawn projects, Section 8.1 Table 8.6, from and adding generation in DPP that were not already included in the Phase 3 model, Section 8.1 Table 8.7 to the starting case. Study cases were created by adding SEMNIA November 2011 Cycle projects and its thermal upgrades, as well as other SPA November 2011 Minnesota Group generating facilities into the benchmark case.

Below is the list of all SPA November 2011 Minnesota Group projects and their dispatch levels in the SEMNIA 2011 November Cycle stability study case.

Table 4.1 – SPA November 2011 Minnesota Group Projects

MISO Proj. Num

Study Group

Service Type

Control Area County State MW

Dispatch Level (MW)

Fuel Type POI Stability

Model

Study Project

G771 SEMNIA NR ALTW Howard IA 200 200 Wind

345 KV line near Afton or

Howard Township

Generic Type 3

G991 SEMNIA NR ALTW Fillmore MN 200 200 Wind Alliant 161 kV GE 1.5 MW

type 3

J177 SEMNIA ER XEL St.

Croix WI 97.5 97.5 Wind

Pine Lake - Apple River

161kV

NX00CB V2, 2.5 MW N100 AP C PSSE

V2.1

J216 SEMNIA NR SMMPA Mower MN 25 25 Wind Austin

Northeast 69 kV Substation

NX00CB V2, 2.5 MW N100 AP C PSSE

V2.1

Other MN study projects

7 GI SPA 2008 Nov BigStone Phase 3 SIS Report https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID=101461


22

MISO Proj. Num

Study Group

Service Type

Control Area County State MW

Dispatch Level (MW)

Fuel Type POI Stability

Model

H041 Buffalo Ridge

ER XEL Lincoln MN 400 0 Wind 115 kV Buffalo

Ridge Substation

SMK203 V1.2, 2.3 MW

J193 Individua

l NR GRE

Otter Tail

MN 50 10 Wind Tamarac 115

kV sub S88001 V2.02A

A portion of the MN 2011 November SPA withdrew during the study process and were not included in the SEMNIA stability study model, Section 8.1 Table 8.5.

The net generation MW change between the withdrawn projects and the new DPP projects and SPA 2011 November Cycle projects was offset by following remote MISO merit dispatch tier order (MTEP10 RMD sheet).

Study wind generators are modeled as one single equivalent machine representing the appropriate dispatch level. The equivalent wind power plant (WPP) power flow presentation is shown below in Figure 4.1.

Figure 4.1 – Single-Machine Equivalent Power Flow Presentation for a WPP

(Source: NREL WECC Wind Generator Development Final Project Report8)

If customer specified data are available, the customer submitted data were used to model the interconnection transmission line, station transformer(s), collector system equivalent, pad-mounted transformer equivalent and wind turbine generator. If customer specified data are not available, the following assumptions were used:

Wind turbine assumption If turbine model is unknown, generic Type 3 turbine is used.

Wind turbine reactive assumption If turbine reactive capability is unknown, the following assumptions are used:

Type 1, Type 2 WTGs: Assume PF = 0.9, Qgen = Qmin = Qmax= - 0.5Pgen. Type 3, Type 4 WTGs: Assume steady-state voltage control PF = +/- 0.95, Qmax

= Pgen × tan[arccos (0.95)] = − Qmin Wind turbine Pad-Mounted Transformer

If wind turbine pad-mounted transformer parameters are unknown, the following assumptions are used:

8 http://uc-ciee.org/downloads/WGM_Final_Report.pdf


23

Assume they have impedance of approx. 6% on the transformer MVA base, with X/R ratio of about 8.

Substation main transformer If substation main transformer parameters are unknown, the following assumptions are used:

Assume Z% = 10% on the transformer’s self-cooled MVA base, with X/R ratio in the range of 40 to 50.

4.3 Dynamic Model The starting dynamic snapshot is the SPA 2008 November Big Stone Phase 3 stability final stability snapshot. All the SPA 2011 November MN projects were added to the snapshot. The following channels were added to the model in SPA MN 2008 Big Stone Phase 3 study,

High Queue Generators Added: o P-Power o Q-Reactive Power

SPA Phase 3 Generators: o ETRM- Machine Terminal Voltage o VOLT- POI Bus Voltage

SPA Phase 3 Regional Plan New Busses: o VOLT- Bus Voltage

The following channels were added to the mode in SPA MN 2011 Big Stone study,

SPA 2011 November Cycle generator: o Real Power

Electric Power Mechanic Power

o Reactive Power Electric Power

o Machine Terminal Voltage o Point of Interconnection Bus Voltage o Point of Interconnection Bus Angle


24

4.4 Disturbances Studied A total of 65 faults were proposed to run for SEMNIA study group:

33 regional faults, Table 4.2 16 local faults, Table 4.3 16 765 kV faults, Table 4.4

Table 4.2 – Regional Faults

Fault Initial Clearing Backup Clearing

Fault Bus Name Type At Time (cycles) Initial Trip At Time

(cycles) Backup Trip

Arcadian 345kV (Bus 1)

SLG 4.5

Arcadian - Pl. Prairie - ckt 1 Arcadian - Granville - ckt 1 Arcadian 345/138 kV - ckt 1

Arcadian Bus 1 - Bus 2 - ckt 1

N Appleton 345kV (at 2s)

Kewaunee 345kV (at 5s)

3-phase 3-phase

4 4.5

N Appleton - FoxRiver - ckt 1 Kewaunee - N Appleton - ckt 1

Edgewater 345kV SLGBF 5.0 Edgewater - Unit 4 - ckt 1 17.5 Edgewater - CEDRSAUK - ckt 1Edgewater 345/138kV XF - ckt 2

Pleasant Prairie 345kV

SLGBF 4.0 5.0

Pleasant Prairie 2 - Pleasant Prairie 1 - ckt 1

Pleasant Prairie 2 - Zion - ckt 1 10.5


Pleasant Prairie - Racine - ckt 1

Emery 161kV 3-phase 5.0 Disconnect Emery Gen

Emery 161/18.0kV XF - ckt 1

Lansing 161kV 3-phase 5.0 Disconnect Lansing Gen

Lansing 161/22.0kV XF - ckt 1 Arnold 345kV 3-phase 4.0 Arnold - Hazleton - ckt 1

Louisa 345kV 3-phase 0.0 4.0 4.0

Louisa - Oak Grove - ckt 1 (Prior-outage)

Louisa - Sub T - ckt 1 Sub T - Hills - ckt 1

Dorsey 500kV 3-phase 4.0 Dorsey - Riel - ckt 1 34.0

Disconnect Limestone 13.8kV bus

Disconnect LONGS 8G 13.8kV bus

Disconnect LONGS 9G 13.8kV bus

Disconnect KETTLE9G 13.8kV bus



Grand Rapids 230kV SLGBF 16.0 Trip Grand Rapids Gen Arrowhead 345kV 3-phase 4.0 Arrowhead - Stone Lake - ckt 1 Stone Lake 345kV 3-phase 4.0 Stone Lake - Arrowhead - ckt 1

Gardner Park 345kV 3-phase 4.0 Gardner Park - Stone Lake - ckt

1

Leland Olds 345kV 3-phase 4.0 Ft. Thompson - Leland Olds - ckt

1

As King 345kV 3-phase 4.0 As King - Eau Claire - ckt 1

Eau Claire - Arpin - ckt 1


25




Praire Island 345kV 3-phase 4.0

Praire Island - North Rochester - ckt 1

North Rochester - Byron - ckt 1 Eau Claire - Arpin - ckt 1

Sherco 345kV 3-phase 4.0 Sherco - Benton - ckt 1 Cass Lake 230kV 3-phase 4.0 Cass Lake - Boswell - ckt 1 Cass Lake 230kV 3-phase 4.0 Cass Lake - Wilton - ckt 1

Center 345kV 3-phase 4.5 Center - Jamestown - ckt 1

Cedar Mtn 345kV 3-phase 4.0 Helena - Cedar Mtn - ckt 1 Helena - Cedar Mtn - ckt 2

Hampton Corner 345kV

3-phase 4.0 Hampton Corner - NROC - ckt 1

Chisago Co 500kV 3-phase

0.0 0.0 3.0 3.5 3.5 3.5 3.5 3.5 3.5 4.0 4.0 5.0 5.0 5.0 5.0

Block Coal Creek - Dickinson - ckt 1

Block Coal Creek - Dickinson - ckt 2

Dorsey - Dorsey S - ckt 2 Disconnect Chisago Disconnect Chisago

Disconnect Chisago T19 34.5kVDisconnect Chisago T29 34.5kVUnblock Coal Creek - Dickinson -

ckt 1 Unblock Coal Creek - Dickinson -

ckt 2 Disconnect Chisago N 500kV Disconnect Chisago 500kV Disconnect Forbes 230kV

Disconnect RoseauN 500kV Disconnect RoseauS 500kV Trip Forbes 500kV Switched

Shunts

Forbes 500kV SLGBF 5.0 5.0 5.0

Move Impedance to RoseauN - Roseau S - ckt 1

RoseauN - Dorsey - ckt 1 Reduce fault admittance

16.0 16.0 16.0 16.0 16.0 17.0 17.0 17.0 18.0 20.0 20.0

Reduce fault admittance Split Forbes 500kV to 600999

Move Forbe SVC - Forbes - ckt 1 to New Forbes bus 600999

Move CHIS-N - Forbes - ckt 1 to New Forbes bus 600999

Split forbes busses to isolate fault

Disconnect Forbes 500kV Disconnect RoseauN 500kV Disconnect RoseauS 500kV

Disconnect Forbes SVC 500kV Disconnect CHIS-N 500kV

Disconnect New Forbes bus 600999

Antelope Valley 345kV

3-phase 4.0 Antelope - Leland Olds - ckt 1

Leland Olds 345kV 3-phase 4.0 Leland Olds 345/230kV XF - ckt

1 COL 345kV SLGBF 5.0 Columbia - N. Madison - ckt 1 18.5 Rockdale - Columbia - ckt 1

Pleasant Prairie 345kV

SLGBF 5.0 Zion - Pleasant Prairie - ckt 1 18.5




26




Point Beach 345kV SLGBF 5.0 Point Beach - SEC - ckt 1 18.5

Point Beach 2 - Point Beach 1 - ckt 1

Point Beach 345/13.8kV XF - ckt 1

Disconnect Point Beach Gen

Kewaunee 345kV SLGBF 5.0 North Appleton - Kewaunee - ckt

1 18.5

Adams 345kV SLGBF 4.0 Adams - Pleasant Valley - ckt 1 16.0 Adams - Mitchell Co. - ckt 1

Disconnect Adams 161kV bus

As King 345kV SLGBF 4.0 As King - KOLMNLK - ckt 1 19.25 As King - Eau Claire - ckt 1

Eau Claire - Arpin - ckt 1

Edgewater 345kV SLGBF 5.0 Edgewater 345/22.0kV XF - ckt 1

Disconnect Edgewater Gen 14.0

Edgewater - CEDRSAUK - ckt 1Edgewater 345/138kV XF - ckt 2

Table 4.3 – 765 kV Faults

Name Fault Type Faulted Bus Initial Trip at time

(cycles)

SPA-MG3 3 Ph Mitchell County 765kV Mitchell County 765kV - Genoa 765kV #P1 3

SPA-BP3 3 Ph Byron 765kV Byron 765kV - Plano 765kV #P1 3

SPA-NB3 3 Ph North Monroe 765kV North Monroe 765kV - Byron 765kV #P1 3

SPA-GN3 3 Ph Genoa 765kV Genoa 765kV - North Monroe 765kV #P1 3

SPA-HK3 3 Ph Hills 765kV Hills 765kV - Kewanee 765kV #P1 3

SPA-KP3 3 Ph Kewanee 765kV Kewanee 765kV - Pontiac 765kV #P1 3

SPA-PG3 3 Ph Pontiac 765kV Pontiac 765kV - Greentown 765kV #P1 3

SPA-NG3 3 Ph New Station 765kV New Station 765kV - Grimes 765kV #P1 3

SPA-LN3 3 Ph Lakefield 765kV Lakefield 765kV - Split Rock 765kV #P1 3

SPA-BS3 3 Ph Big Stone 765kV Big Stone 765kV - Brookings County 765kV #P1 3

SPA-HH3 3 Ph Hazleton 765kV Hazleton 765kV - Hills 765kV #P1 3

SPA-HM3 3 Ph Helena 765kV Helena 765kV - Mitchell County 765kV #P1 3

SPA-SR3 3 Ph Split Rock 765kV Split Rock 765kV - Raun 765kV #P1 3

SPA-BR3 3 Ph Brookings County 765kV Brookings County 765kV - Split Rock 765kV #P1 3

SPA-GH3 3 Ph Grimes 765kV Grimes 765kV - Hills 765kV #P1 3

SPA-RN3 3 Ph Raun 765kV Raun 765kV - New Station 765kV #P1 3

Table 4.4 – SEMNIA group Local Faults

Name Project

Fault Type Faulted Bus Initial Trip

At time

(cycles)

Backup Trip At

time (cycle

s)

SPA-MH3 G771 3 Ph Mitchell Co. 345 Mitchell Co. - Hazlton 345 kV

4

SPA-MA3 G771 3 Ph Mitchell Co. 345 Mitchell Co. - Adams 345 kV

4

SPA-HL3 G991 3 Ph G746_TAP 161 G746 - Lansing 161 kV 6

SPA-LH3 G991 3 Ph G746_TAP 161 G746 - Harmony 161 kV 6


27

Name Project

Fault Type Faulted Bus Initial Trip

At time

(cycles)

Backup Trip At

time (cycle

s) SPA-AP3 J177 3 Ph J177_TAP 161 J177 - Pine lake 161 kV 6

SPA-PA3 J177 3 Ph J177_TAP 161 J177 - Apple river 161 kV 6

SPA-AM3 J216 3 Ph Austin 69 Austin - Mound Prairie 69 kV

8

SPA-AH3 J216 3 Ph Austin 161 Austin - Hayward 161 kV 6

SPA-MHS G771 SLG Hazlton 345 kV Mitchel Co. - Hazlton 345 kV

4 Hazlton 345/161 transformer 18

SPA-MAS G771 SLG Adams 345 kV Mitchel Co. - Adams 345 kV

4 Adams 345/161/13.8 transformer

11

Pleasant Valley - Adams 345 kV 11

SPA-LHS G991 SLG Harmony 161 kV G746_Tap - Harmony 161 kV

6 Harmony - Beaver Creek 161 kV 18

Harmony - Genoa 161 kV 18

Harmony 161 /69 transformer 18

SPA-HLS G991 SLG Lansing 161 kV G746_Tap - Lansing 161 kV

6 Lansing - Genoa 161 kV 18

Lansing 161 kV bus tie 18

Lansing 161/22 kV transformer 18

SPA-PAS J177 SLG Apple River 161 kV

J177_Tap - Apple River 161 kV

6 Apple River 161/69 kV transformer

18

SPA-APS J177 SLG Pine Lake 161 kV J177_Tap - Pine Lake 161 kV

6 Pine Lake 161 kV bus tie 18

Pine Lake - Rush River 161 kV 18

SPA-AHS J216 SLG Hayward 161 kV Austin - Hayward 161 kV 6 Hayward - Glenworth 161 kV 18

Hayward 161/69 transformer 18

Hayward 161kV bustie 18

SPA-AAS J216 SLG Adams 161 kV Austin - Adams 161 kV 6 Adams 161 kV bustie S_N 18

Adams 161 kV bustie N 18

Adams - Hiprar 161 kV 18

Adams - Rochester 161 kV 18

4.5 Results All fault disturbance simulations were stable and showed no violations. No stability constraints were identified in SEMNIA group study.


28

5 SHORT CIRCUIT MISO performed a limited scope short circuit analysis for SEMNIA Phase 3 projects. Single Line to Ground and Three Phase fault current values were calculated for concerned buses in Phase 3 projects. The SEMNIA Phase 3 project has identified short circuit current at Byron B 345kV, Byron R 345kV, and Wayne138kV exceeded the assumed circuit breaker interrupting value(40kA). At all other observed buses, short circuit current values for both Single Line to Ground and Three Phase faults appears to be below the circuit breaker interrupting values. The actual breaker rating will be further reviewed against the fault current in DPP phase. . There are no changes in transmission assumptions from SEMNIA Phase 3 project when compared to the MN November 2011 projects. Hence, the short circuit study results will be further reviewed when the study project’s proceeds to DPP analysis. The complete report for SEMNIA Phase 3 short circuit study can be found at the link below: https://www.midwestiso.org/Library/Repository/Study/Generator%20Interconnection/GI-SPA-2008-NOV- Big_Stone_Phase_3-SIS_Report.zip


29

6 NETWORK UPGRADES AND COST ALLOCATION 6.1 Network Upgrades Transmission upgrades were identified via power flow analysis. DPC and ITC Midwest provided assumptions to determine the cost for upgrades of facilities in their control area. Interconnection service for SPA November 2011 SEMNIA projects would be conditional upon previously identified network upgrades included as basecase assumptions. Network upgrades identified for study projects are mentioned in Table 6.1.

Table 6.1 – SEMNIA 2011 ERIS Network Upgrades

Facility Upgrade Estimated Cost ($M)

Lansing - Genoa 161kV Rebuild Lansing – Genoa 161kV 15.00Estimated Total 15.00

Deliverability analysis is performed for Network Resource (NR) requests at 100% of the requested output. Table 6.2 provides upgrades that were required to mitigate constraints that limited the output of generation, making them not 100% delieverable.

Table 6.2 – SEMNIA 2011 Delieverabily Network Upgrades

Facility Upgrade Estimated Cost ($M)

Harmony - G991 Tap 161kV ckt1 Rebuild Harmony - G991 Tap 161kV ckt1 to 446 MVA 4.50Estimated Total 4.50

6.2 Shared Network Upgrades The Regional Transmission Upgrades included in the base model for the SPA 2011 SEMNIA study was initially identified via a linear power flow analysis for the SPA 2008 Phase 3 study. These upgrades, as defined above are required to unlock the regional bottlenecks for all generation projects in Phase 3 of the SPA studies. A planning level cost estimate for Regional Transmission Upgrades is approximately $10 billion as reported in Table 6.3. The full details of the Phase 3 regional plan are available in the Phase 3 SEMNIA study9. SEMNIA 2011 projects will be studied for shared network upgrade cost allocation of regional network upgrades that meet the sharing requirement as defined in the generator interconnection business process manual10.

9 Phase 3 SEMNIA report: https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=101461 10 The Generator Interconnectino BPM is BPM 015: https://www.misoenergy.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesManuals.aspx


30

Table 6.3 – Regional Upgrade Plan



Big Stone-Brookings Co 765 kV 63 336.4

Big Stone-Canby 345 kV 51 100.9

Canby-Hazel 345 kV 44 79.2

Hazel-Panther 345 kV 39 70.2

Panther-McLeod 345 kV 27 71.8

McLeod-Blue Lake 345 kV 47 84.6

Split Rock-Brookings Co. 765 kV 60 347.9

Brookings Co - Helena 765 kV 149 603.4

Helena-Mitchell Co 765 kV 113 533.4

Mitchell Co-Hazleton 765 kV 78 387.5

Hazleton-Hills 765 kV 77 384.3

Split Rock-Lakefield 765 kV 77 407.4

Lakefield-Mitchell Co 765 kV 128 417.3

Split Rock-Raun 765 kV 105 473.9

Raun-New Station 765 kV 71 252.3

Lakefield -New Station 765 kV 140 448

Brookings Co-Lakefield 765 kV 115 402.5

New Station-Grimes 765 kV 107 480.3

Grimes-Hills 765 kV 118 514.9

Mitchell Co-Genoa 765 kV 73 424.9

GRE Pleasant Valley-Preston 345 kV 37 72

Preston-Genoa 345 kV 66 144.6

Preston-H028 Tap 345 kV 37 77.9

Genoa-North La Crosse 345 kV 29 66.8

Genoa-North Monroe 765 kV 132 690.3

North Monroe-Byron 765 kV 58 370.7

Byron-Plano 765 kV 77 226.8

Byron-Charter Grove 345 kV 40 95.8

Charter Grove-Wayne 345 kV 14 35.3

Hills-Kewanee 765 kV 117 497

Kewanee-Pontiac 765 kV 88 384.9

Kewanee-Collins 345 kV 66 104.9

Pontiac-Greentown 765 kV 169 485.8

Hills-Barstow 345 kV 93 164.1

Barstow-Kewanee 345 kV 23 34.5

11 Total Estimated Costs include substation, transformer, and line costs


31



Total $10,27312

Figure 6.1 – Phase 3 Regional Transmission Plan

Shared Network Upgrade (SNU) cost allocation methodology was used to determine share of study Projects for network upgrades identified for higher queued projects that are modeled in base case. It was found that SPA 2011 Minnesota Buffalo Ridge, SEMNIA, and J193 projects will share cost transmission upgrades with Group Study 5, DPP 2009 March, and SPA 2008 November Minnesota Phase 3 Projects. Table 6.4 summarizes the share network upgrade cost responsibility for SPA 2011 SEMNIA Projects.

Table 6.4 – Shared Network Upgrade Cost Allocation

Upgrade Rating(MVA)

Type of Upgrade

Facility Cost ($M)

G771 ($M)

G991 ($M)

J177 ($M)

J216($M)

Mitchell County - Hazelton 765 ckt 1 5300 New


Genoa 345/161 Transformer 336 New

Equipment 11.80

3.37

12 Slight modification to the Phase 3 cost due to approval of MTEP Appendix B projects moving to Appendix A.


32

Upgrade Rating(MVA)

Type of Upgrade

Facility Cost ($M)

G771 ($M)

G991 ($M)

J177 ($M)

J216($M)

Genoa - North Monroe 765 ckt1 5300 New

Equipment 529.20 7.62 7.64

Byron 765 - North Monroe 765kv ckt1 5300 New

Equipment 232.80 3.30 3.41

Adams 345/161 Transformer 300 New

Equipment 11.40

1.13

Adams - South Adams 161kV ckt1 473.1 Reconductor 0.35 0.05

Beaver Creek - Harmony 161kV ckt1 249.6 Reconductor 2.91 0.86


Equipment 56.4 6.35


Equipment 56.4 6.35

Mitchell County Substation 345/765

Substation New


Total Estimated Cost: 40.23 16.46 0.00 0.00

6.3 Cost Allocation Network upgrade costs for the SPA 2011 SEMNIA project is provided below


Project Num

ERIS Network Upgrades ($M) NRIS Network

Upgrades ($M) Interconnection

Facilities ($M)


($M)

Estimated Cost ($M)

$/MW ($M) Thermal

($M)


state and dynamic)

Short-circuit($M)

Deliverability ($M)

G771 0 0 0 0 5.00 40.23 45.23 0.23

G991 15.00 0 0 4.50 5.00 16.46 40.98 0.21

J177 0 0 0 0 5.00 0 5.00 0.05

J216 0 0 0 0 5.00 0 5.00 0.20 Total ($M) 15.00 0 0 4.50 20.00 56.69 96.19 Average

0.17


33

7 CONCLUSIONS The study was performed under the SPA 2011 Cycle for the SEMNIA study area. It is one of three study groups in Minnesota. Other groups being studied in parallel include the Buffalo Ridge and Big Stone Area. The study identified one Network Upgrade to interconnect the 522.5MW of generation included in the SEMNIA Area. Also utilized in the study was regional upgrades identified in previous SPA cycles that were analyzed for cost sharing responsibilities for the current cycle. The previously identified regional upgrades consist of nearly $11 billion, creating a 765 kV transmission backbone. The local upgrades identified for the current study projects account for $15 million in mitigation. All cost estimates provided in the report are planning level good faith estimates without any engineering or design review. Thermal constraints identified in the summer off peak conditions are listed in Table 3.5 in the report. The table included all constraints due to SEMNIA 2011 projects. No voltage violations was identified and no new VAR support is required beyond what was identified in the SPA 2008 Phase 3 Minnestoa Study. No constraints were identified in summer peak analysis after including SPA 2011 SEMNIA local mitigation. Both G771 and J216 were found to be fully deliverable. G991 is limited to 68 MW of deliverability or G991 can elect to upgrade the Harmony to G991 tap 161 kV line for a cost of $4.50 million. All projects requesting Network Resource integration are contingent upon the ERIS analysis upgrades and SPA SEMNIA 2011 upgrades being in place. The total cost of network upgrades for the 2011 SEMNIA projects is $92.21 Million, summarized inTable 7.1.


Project Num

ERIS Network Upgrades ($M) NRIS Network

Upgrades ($M) Interconnection

Facilities ($M)


($M)

Estimated Cost ($M)

$/MW ($M) Thermal

($M)


state and dynamic)

Short-circuit($M)

Deliverability ($M)

G771 0 0 0 0 5.00 40.23 45.23 0.23

G991 15.00 0 0 4.50 5.00 16.46 40.98 0.21

J177 0 0 0 0 5.00 0 5.00 0.05

J216 0 0 0 0 5.00 0 5.00 0.20 Total ($M) 15.00 0 0 4.50 20.00 56.69 96.19

Average 0.17


34

8 Appendices 8.1 Modeling Documentation

8.1.1 Starting Model SPA 2011 MN (Cycle 4) study started with the SPA 2008 MN Phase 3 study model13. The regional plan proposed in the Phase 3 study is modeled as a starting point for the SPA 2011 MN study. The Share Network Upgrade methodology will be analyzed for the Phase 3 regional plan as described in the Generator Interconnection BPM 015. The detailed modeling information for the SPA Phase 3 study is available in the appendix of the posted Phase 3 reports:

Big Stone: https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID=104798 Buffalo Ridge: https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID=101460 Southeast Minnesota and North Iowa: https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID=101461

The Phase 3 regional 765 kV plan is summarized as the following new facilities:

Table 8.1 – Regional 765kV Summarized Plan

kV Level From Bus To Bus Miles State R X Bsh Reactors at each end

765 Split Rock Brookings Co. 60 MN/Dak 0.00018 0.00522 2.86470 0.71618

765 Brookings Co. Helena 149 MN/Dak 0.00045 0.01296 7.11400 1.77850

765 Helena Mitchell Co. 113 MN/Dak 0.00038 0.01088 5.96810 1.49203

765 Mitchell Co. Hazleton 78 IA 0.00023 0.00679 3.72411 0.93103

765 Hazleton Hills 77 IA 0.00023 0.00670 3.67637 0.91909

765 Split Rock Lakefield 77 MN/Dak 0.00023 0.00670 3.67637 0.91909

765 Lakefield Mitchell Co. 128 MN/Dak 0.00038 0.01114 6.11136 1.52784

765 Split Rock Raun 105 IA 0.00032 0.00914 5.01323 1.25331

765 Raun New Station 71 IA 0.00021 0.00618 3.38990 0.84747

765 Lakefield New Station 140 IA 0.00042 0.01218 6.68430 1.67108

765 New Station Grimes 107 IA 0.00032 0.00931 5.10872 1.27718

13 SPA 2008 MN Phase 3 study includes projects from the SPA November 2008, November 2009, and November 2010 cycles.


35

kV Level From Bus To Bus Miles State R X Bsh Reactors at each end

765 Grimes Hills 117.8 IA 0.00035 0.01025 5.62436 1.40609

765 Hills Kewanee 117 IL/Comed 0.00035 0.01018 5.58617 1.39654

765 Kewanee Pontiac 88.2 IL/Comed 0.00027 0.00767 4.21111 1.05278

765 Pontiac Greentown 169 IL/Comed 0.00051 0.01470 8.06891 2.01723

765 Genoa North Monroe 132.31 WI 0.00040 0.01151 6.31714 1.57929

765 North Monroe Byron 58.2 WI 0.00018 0.00506 2.77876 0.69469

765 Byron Plano 76.5 IL/Comed 0.00023 0.00666 3.65249 0.91312

765 Big Stone Brookings Co. 63 MN/Dak 0.00019 0.00548 3.00794 0.75198

765 Brookings Co. Lakefield 115 MN/Dak 0.00035 0.01001 5.49068 1.37267

765 Mitchell Co Genoa 73 MN/Dak 0.00020 0.00630 3.64440 0.91110

345 Kewanee Collins 66 IL/Comed 0.00247 0.03267 0.55935

345 Byron Charter Grove 40 WI 0.00129 0.02060 0.21180

345 Charter Grove Wayne 14 WI 0.00097 0.00156 0.16000

345 North La Crosse Genoa 29 MN 0.00178 0.02411 0.44730

345 Hazel Panther 39 MN/Dak 0.00180 0.01973 0.33670

345 Panther Mcleod 27 MN/Dak 0.00123 0.01349 0.23020

345 Mcleod Blue Lake 47 MN/Dak 0.00214 0.02337 0.40040

345 Hills Barstow 93 IA/IL 0.00365 0.04618 0.79275

345 Barstow Kewanee 23 IA/IL 0.00088 0.01117 0.19180

*345 Black Hawk Hazleton 24 IA 0.00096 0.01152 0.21600

Table 8.2 – MTEP Appendix B Projects

Action Bus # Bus Name kV Bus # Bus Name kV Ckt MTEP Project Name

Tap Branch 238615 02CHAMBR 345 238941 02MANSFD 345 1 Project 1607

Add Branch 238615 02CHAMBR 345 238781 02HANNA 345 1 Project 1607

Add Branch 238781 02HANNA 345 238941 02MANSFD 345 1 Project 1607


36

Action Bus # Bus Name kV Bus # Bus Name kV Ckt MTEP Project Name

Tap Branch 238715 02FERNWY 138 238813 02HOYTDL 138 1 Project 1612

Tap Branch 238833 02JACKSN 138 239141 02TRACO 138 1 Project 1612

Add Branch 238715 02FERNWY 138 239281 02CRNBRY 138 1 Project 1612

Add Branch 238813 02HOYTDL 138 239281 02CRNBRY 138 1 Project 1612

Add Branch 238833 02JACKSN 138 239281 02CRNBRY 138 1 Project 1612

Add Transformer 239280 02CRNBRY 500 239281 02CRNBRY 138 1 Project 1612

Add Bus 239281 02CRNBRY 138 Project 1612

Add Branch 239141 02TRACO 138 239281 02CRNBRY 138 1 Project 1612

Remove Branch 238961 02MIDWAY 345 239018 02NTAP 345 1 Project 2250

Add Branch 238961 02MIDWAY 345 239313 02FULTON 345 1 Project 2250

Add Branch 239018 02NTAP 345 239313 02FULTON 345 1 Project 2250

Add Transformer 238738 02FULTON 138 239313 02FULTON 345 1 Project 2250

Add Bus 239313 02FULTON 345 Project 2250

Add Branch 255259 17CHIAVE 345 255103 17DUNACR 345 1 Project 2326

Add Branch 255259 17CHIAVE 345 255111 17SHEFLD 345 1 Project 2326

Add Bus 255259 17CHIAVE 345 Project 2326

Add Transformer 255259 17CHIAVE 345 255124 17CHIAVE 138 1 Project 2326

Delete Branch 255103 17DUNACR 345 255251 17GARYAV 345 1 Project 2326

Delete Branch 255111 17SHEFLD 345 255251 17GARYAV 345 1 Project 2326

Delete Branch 255124 17CHIAVE 138 255252 17GARYAV 138 1 Project 2326

Add Transformer 239280 02CRNBRY 500 239281 02CRNBRY 138 2 Project 2326

Add Transformer 255251 17GARYAV 345 255252 17GARYAV 138 2 Project 2326

Add Bus 255251 17GARYAV 345 Project 2326

Add Bus 255252 17GARYAV 138 Project 2326


37

Table 8.3 – MVP Projects Added to the Model

kV Level From Bus To Bus Miles State

MTEP Project

ID Notes

345 Oakgrove Galesburg 32 IL 3022 MVP16

345 Galesburg Fargo 45 IL 3022 MVP16

345 Dubuque Spring Green 75 WI 3127 MVP5

345 Spring Green West

Middleton 28 WI 3127 MVP5

345 North La Crosse North Madison 136 WI 3127 MVP5

345 North Madison West

Middleton 21 WI 3127 MVP5

345 Lakefield Winnebago 55 MN 3205 MVP3

345 Winnebago Winco 38 MN/IA 3205 MVP3

345 Winco Burt 2.73 IA 3205 MVP3

345 Sheldon Burt 63 IA 3205 MVP3

345 Burt Webster 63 IA 3205 MVP3

345 Winco Lime Creek 50 IA 3213 MVP4

345 Lime Creek Emery 11 IA 3213 MVP4

345 Emery Black Hawk 73 IA 3213 MVP4

345 Black Hawk Hazleton 24 IA 3213 MVP4

8.1.2 Generation Interconnection Projects Table 8.4 – SPA 2011 MN Study Projects (SPA Cycle 4)

MISO Project No. Group Control Area County State MW Fuel Type Point of Interconnection Dispatch Level MW Type

G771 SE MN IA ALTW Howard IA 200 Wind Mitchell County 345 kV 200 NR

G991 SE MN IA ALTW Fillmore MN 200 Wind Harmony - Lansing 161 kV 200 NR

H041 Individual XEL (NSP) Lincoln MN 400 Wind 115 kV Buffalo Ridge Substation 0 ER

J177 SE MN IA XEL (NSP) St. Croix WI 97.5 Wind Pine Lake - Apple River 161kV 97.5 ER


38

MISO Project No. Group Control Area County State MW Fuel Type Point of Interconnection Dispatch Level MW Type

J193 Individual GRE Otter Tail MN 50 Wind Tamarac 115 kV sub 10 NR

J216 SE MN IA SMMPA Mower MN 25 Wind Austin Northeast 69 kV Substation 25 NR

Table 8.5 – SPA 2011 MN Withdrawn Projects (SPA Cycle 4) MISO

Project No.

Group Control Area County State MW Fuel

Type Point of Interconnection Type

G670 SE MN IA XEL (NSP) Faribault MN 200 Wind Winnebago - Hayward 161 kV NR

G959 SE MN IA XEL (NSP) Goodhue MN 200 Wind Twin Cities to LaCrosse 345 kV line NR

G960 SE MN IA XEL (NSP) Goodhue MN 200 Wind Twin Cities to LaCross 345kV line NR

G961 SE MN IA XEL (NSP) Goodhue MN 200 Wind Twin Cities to LaCrosse 345kV line NR

H025 Buffalo Ridge XEL (NSP) Minnehaha SD 200 Wind Anson Substation NR

J175 Individual MP Saint Louis MN 30 Biomass MP Virginia 115kV Substation ER

J179 SE MN IA XEL (NSP) Goodhue MN 47.5 Wind Xcel Goodhue 69kV Substation NR

J180 SE MN IA XEL (NSP) Goodhue MN 39 Wind Xcel Goodhue 69kV Substation NR

Table 8.6 – Withdrawn or Parked for One Year High Queue Projects

MISO Project

No. Group Name Service

Type Control

Area County State POI per Model MW Fuel Type

G282 ATC ER ALTE Lafayette WI Darlington to Hillman 138 kV 99 Wind

G427 ATC NR WEC Fond du lac WI Cypress 345 kV 98 Wind

G546 ATC NR WEC Walworth WI North Lake 138 kV 100 Wind

G611 ATC NR WEC Calumet WI Tecumseh Rd. to Forest Junction 138 kV 99 Wind

G703 SD Group NR XEL Hand/Hyde SD Split Rock 345 kV 1500 Wind

G704 SD Group NR XEL Hand/Hyde SD Split Rock 345 kV 1500 Wind

G705 SD Group NR XEL Hand/Jerauld SD Brookings Co 345 kV 2000 Wind

G749 ATC NR ALTE Lafayette WI Hamilton St. to Eden 69 kV 50 Wind

G773 ATC NR WPS Brown WI Forest Jct. to Lost Dauphin 138 kV 150 Wind


39

MISO Project

No. Group Name Service

Type Control

Area County State POI per Model MW Fuel Type

G852 South East MN-IA NR XEL Dodge, Olmstead MN GRE Pleasant valley to Byron 161 kV line 300 Wind

G857 South East MN-IA NR XEL Mower MN Adams 345 kV 400 Wind

G871 South East MN-IA ER ALTW Freeborn MN Hayward 161 kV 201 Wind

G903 Big Stone Area ER XEL Wright MN Crow River 115 kV 2000 Wind

G927 ATC NR WEC Calumet WI Elkhart Lake 138 kV 2 Wind

G939 Big Stone Area NR OTP Grant SD Big Stone 230 kV 250 Wind

G963 South East MN-IA NR ALTW Mitchell IA Mitchell County 345 kV 200 Wind



H011 South East MN-IA NR ALTW Mower MN Stewartville 69 kV 250 Wind

H028 South East MN-IA NR XEL Olmsted MN North Rochester to North La Crosse 345 kV

line 299 Wind

H031 Big Stone Area NR OTP Wilkin MN Fergus Fall - Wahpeton 230 kV line 160 Wind

J007 Buffalo Ridge NR ALTW Osceola IA Lakefield -- Raun 345 kV 250 Wind

J029 DPP July 2009 IA NR ALTW Howard and

Mitchell IA Mitchell County Substation 102 Wind

J045 Buffalo Ridge NR XEL Pipestone MN Rock River-South Ridge 69 kV line 23.1 Wind

J072 Buffalo Ridge NR ALTW O'Brien IA Lakefield 345kV 200.1 Wind

J080 Big Stone Area NR XEL Brookings SD Brookings Co 345 kV 200 Wind

J095 South East MN-IA NR ALTW Cerro Gordo &

Hancock IA Hancock to Cerro Gordo 161 kV line 300 Wind

J111 South East MN-IA NR GRE Mower MN Pleasant Valley 345 kV 150 Wind

J139 South East MN-IA NR DPC Grant WI Gran Grea to Nelson Dewey 161 kV line 200 Wind

J151 Buffalo Ridge NR XEL Moody SD Split Rock 115 kV 350 Wind

J198 Buffalo Ridge NR XEL Lyon MN Buffalo Ridge – Lake Yankton 115 kV 99 Wind

R50 MEC MEC Washington IA MEC Sub T 345kV 501 Wind

R51 MEC MEC Poweshiek IA Montezuma 345kV 250.5 Wind


40

Generation in DPP that were not already included in the model were added to model the most likely condition.

Table 8.7 – Generation Added to the Model

MISO Project

Num

Overall Project Status

Study Status Study Group

Control Area County State

Max Summer Output

Dispatch Level MW

Fuel Type Point of Interconnection

J171 Active DPP - System Impact Study

GRE Swift MN 7 7 Biomass 100 Industry Drive, Benson, MN

J020 Done GIA Complete XEL (NSP)

Wright MN 24.356 0 Diesel SE corner of Hwy 12 & CR 17 E of Crow River

J021 Done GIA Complete XEL (NSP)

McLeod MN 41.15 0 Diesel 305 11th St. E. & 1019 Armstrongs Ave. N.


XEL (NSP)

Lyon MN 300 0 Gas Lake Yankton substation


GRE Blue Earth MN 161.5 0 Gas Mankato Energy Center substation


XEL (NSP)

Goodhue MN 200 200 Nuclear Existing NSP's Prairie Island Plant


Buffalo Ridge

ALTW Dickson IA 100 20 Wind Switchyard approx. 4 mi S of Triboji Sub

R59 Active DPP - System Impact Study

SEMNIA MEC Wright IA 28 28 Wind Wall Lake (Centruy) - expansion

R68 Active DPP - System Impact Study

SEMNIA MEC Hancock IA 249.6 250 Wind Webster 345 kV Substation

J032 Active Facilities Study Buffalo Ridge

GRE Watonwan MN 4.95 0 Wind Sveadahl - Butterfield 69kV

J033 Done GIA Complete Buffalo Ridge

ALTW Cottonwood MN 4.95 0 Wind 1 pole north of sub, Alliant 69 kV line

J035 Done GIA Complete BigStone OTP Wilkin MN 4.95 0 Wind Pole #54, OTP 41.6 kV line

J036 Active Facilities Study Buffalo Ridge

ALTW Jackson MN 4.95 0 Wind Windom - Heron Lake 69 kV


Buffalo Ridge

ALTW Cottonwood MN 4.95 0 Wind Section 21, Midway Township


SEMNIA DPC Winona MN 4.95 4.95 Wind ITC Midwest 69 KV line southwest corner of section 11, Utica Township


SEMNIA DPC Winona MN 4.95 4.95 Wind Alliant Rushford - Wilson 69kV


Buffalo Ridge

XEL (NSP)

Lyon MN 4.95 0 Wind Xcel 69 kV line, Stanley Township


Buffalo Ridge

XEL (NSP)

Rock MN 200 0 Wind Split Rock Substation

J184 Active DPP - System Buffalo XEL Rock MN 150 0 Wind Split Rock Substation


41

MISO Project

Num

Overall Project Status

Study Status Study Group

Control Area County State

Max Summer Output

Dispatch Level MW

Fuel Type Point of Interconnection

Impact Study Ridge (NSP)


SEMNIA GRE Dodge MN 150 0 Wind Pleasant Valley Substation

8.1.3 Topology Changes

Alexandria 345/115 kV substation correction (purged the two winding transformer in the model and added a three winding transformer (345/115/34.5 kV) with a 50 MVAR switched reactor on the tertiary)

Bison 345/230 kV substation correction (removed 345/230 kV transformers modeled at Bison) Ortonville – G894 – Johnson Jct. 115 kV rating correction, new rating 93 MVA normal and emergency. The Marshall (MMU) North 7th St. load correction, load was set to 43.0 MW active load and 2.6 MVar reactive load. Moorhead 230/115 kV transformers, Moorhead 115 kV line segments rating update for Fargo to Brook to 119MVA as well as Brook to SE

to 127MVA, and Moorehead generation update (generation remains off-line) Ashtabula generation update dispatched at 641 MW and dispatched to the MISO footprint Buffalo-Casselton 115 kV line status correction, status changes to in-service The 615015 Spiritwood plant is dispatched at 100 MW because it is a baseload The Maple River-Sheyenne 230 kV line rating is updated to 459 MVA normal and 505 MVA emergency Maple River-Frontier 230 kV line rating is updated to 364 MVA normal and404 MVA emergency Frontier-Wahpeton 230 kV line rating is updated to 364 MVA normal and 364 MVA emergency Harmony to Generation Tap to Lansing 161kV corrected to 200MVA

The following modeling changes provided by ATC were applied to the model: As-built System Topology Updates Included

20100903_Z2_Straits_25MVAR_Reactors_Xfmr_3-wdg.idv 20100923_Z3_LaMar_Caps_and_Breakers.idv 20101010_Z3_T-D_STO_Stoughton_North.idv 20101206_Z4_Remove_Lakefront_Diesel_Unit_1.idv 20101211_Z2_IndianLake_2x8_16_69kV_Caps.idv 20101213_Z3_T-D_REC_Milton.idv 20110111_Z1-Z4_GEN-GSU_Updates.idv 20110128_z1-z5_Misc_Updates.idv 20110304_Z1_T-D_ACEC_Badger_West.idv 20110401_Z1-Z5_Misc_Updates.idv 20110602_Z3_Dane County Corrective Plan Caps P1.idv 20110603_Z1_AM_AURORA-T3_Replacement.idv


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20110613_Update_Marquette_Modeling.idv 20110613_z3_TD_Richmond_Nv30.idv 20110617_Z5_T-D_WEC_Barland.idv 20110701_Z5_Cedarsauk_Dist_Cap_Retirement.idv 20110811_Z1_MCK_and_CHC_Cap_upgrades.idv 20110822_Z4_G833-J022_KEW_MWMVARMEL.idv 20110901_ATC_Bus_Name_Changes.idv 20110906_ATC_Bus_Tie_Updates.idv 20110909_Z3_Juneau_System_Detail.idv 20111001_Z2_WPPI_LD_Zone_Changes.idv 20111114_Z4_AM_Uprate_796L41_EDG-SAU_345.IDV 20111130_Z4_K-89_CANAL-MICH_ST_69kV.idv/Planned 20111130_Z5_EP_Tosa-Granville-Butler_138kV_Uprate.idv 20111201_Z3b_Jefferson_Dist_Cap_Retirement.idv 20111215_Z3_Brodhead-South Monroe 69 kV line Rebuild_Nv30.idv 20111227_Z5_Bluemound-T3_Replacement.idv 20111231_Z4_Pt_Beach_GSU_proposed-G1.idv Future MTEP A and Network Projects Included 20120101_Z4_AM_C-103_Revere-N_East_Uprate.idv 20120301_Z4_AM_X-50_Progress-Aviation_Uprate.idv 20120301_Z3a_AM_Y-34_Darlington-Jennings_uprate.idv 20120301_Z3b_AM_Y-159_BCH-WAL_uprate.idv 20120323_Z2_Reduce_DELTA_Caps_to_1x5-4MVAR.idv 20120531_Z3_WMD_Name_Chng_2_Cardinal.idv 20120601_Z2_ILK-HIA_138-69_LTC_Vhi-Vlo_v30.idv 20120601_Z4_T-D_Forest_Ave_Alliant_Nv30.idv 20121001_Z2_Engadine_load_move_v30.idv 20121231_Z3_G282_Quiltblock_Gen.idv 20121231_z3_T-D_ALTE_Fountain_Prairie.idv 20130215_z1_AM_Y-80_Omro-Winc_Uprate.idv 20130523_Z5_Pleasant_Prairie_SS_Rbld.idv 20130601_Z3_MGE_WLT_Distr_Cap_Back_to_Service.idv 20130602_Z3 Blount Distribution Cap Bank Retirement.idv 20140306_Z5_SE-WI_P4-ZionEC345.idv 20140501_Z2_Straits_BTB-HVDC-VSC_PSSE_v30.idv 20140601_Z2_PineRiver-Straits_69_rebuild_69_t2-477_v30.idv 20140601_Z3_TD_WEST MIDDLETON_MGE_Upgrade_WMD_TR7_Nv30.idv 20150401_Z5_T-D_WEC_MILWAUKEE_CO_Two_south.idv 20170601_z5_3rd center xfmr_Nv30.idv


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9 Summer Off-Peak Constraints Table 9.1 – Summer Off Peak Constraints before Mitigation

** From bus ** ** To bus ** CKT Contingency Loading MW Rating Loading%

G771 DF (%)

G991 DF (%)

J177 DF (%)

J216 DF (%)

601018 CHIS CO3 345 605587 CHIS D2Y 110 9 601018 CHIS CO3 345 605586 CHIS D1Y 110 10 1439 1385 103.9 <5% <5% 0.05 <5%

601018 CHIS CO3 345 605586 CHIS D1Y 110 10 601018 CHIS CO3 345 605587 CHIS D2Y 110 9 1438.7 1385 103.9 <5% <5% 0.05 <5%

631052 LANSINGW 161 681523 GENOA 5 161 1 631052 LANSINGW 161 631053 LANSING5 161 1 251.1 240 104.6 <5% 0.25 <5% <5%

631052 LANSINGW 161 681523 GENOA 5 161 1 681528 HARMONY5 161 927058 G991_TAP 161 1 276.9 240 115.4 <5% 0.66 <5% <5%

699244 ARP 345 345 699245 ARP 138 138 1 699244 ARP 345 345 699785 ROCKY RN 345 1 351.4 336 104.6 <5% <5% 0.05 <5%

602017 ST LAKE5 161 699450 ST LAKE 345 1 699450 ST LAKE 345 699676 GARDR PK 345 1 343 336 102.1 <5% <5% 0.06 <5%

615306 GRE-PL VLLY3 345 691528 PRESTON3 345 345 1 700552 GENOA765 765 907985 MICHLCO765 765 P1 813.4 600 135.6 0.11 <5% <5% 0.12

631052 LANSINGW 161 681523 GENOA 5 161 1 700552 GENOA765 765 907985 MICHLCO765 765 P1 252 240 105 <5% 0.18 <5% <5%

681523 GENOA 5 161 700012 GENOA 5 345 345 P1 700552 GENOA765 765 907985 MICHLCO765 765 P1 415.6 336 123.7 <5% 0.26 0.06 <5%

601002 ADAMS 3 345 631144 MITCHLCO3 345 1 907985 MICHLCO765 765 927122 HAYWARD 765 765 P1 1031 956 107.8 <5% 0.19 0.12 0.32

631052 LANSINGW 161 681523 GENOA 5 161 1 B3.HAR-AT15 279.8 240 116.6 <5% 0.66 <5% <5%

601018 CHIS CO3 345 605586 CHIS D1Y 110 10 B3_XEL_CHIS_CO110.0-34.5_9 1438 1385 103.8 <5% <5% 0.05 <5%

601018 CHIS CO3 345 605587 CHIS D2Y 110 9 B3_XEL_CHIS_CO110.0-34.5_10 1444.8 1385 104.3 <5% <5% 0.05 <5%


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10 Shared Network Upgrade Cost Allocation Table 10.1 – SPA 2011 SEMNIA Shared Network Upgrade Cost Allocation

Upgrade Distribution Factor Cost Share in % Estimated Cost Share ($M)

G771(%)

G991(%)

J177 (%)

J216(%)

G771(%)

G991(%)

J177 (%)

J216(%)

G771($M)

G991($M)

J177 ($M)

J216($M)

Mitchell County - Hazelton 765 ckt 1 27% 18% 15% 2% 5.05

Genoa 345/161 Transformer 1% 27% 29% 3.37

Genoa - North Monroe 765 ckt1 25% 21% 25% 1% 1% 7.62 7.64

Byron 765 - North Monroe 765kv ckt1 25% 21% 25% 1% 1% 3.3 3.41

Adams 345/161 Transformer 3% 10% 10% 1.13

Adams - South Adams 161kV ckt1 3% 15% 14% 0.05

Beaver Creek - Harmony 161kV ckt1 1% 1% 34% 30% 0.86

Mitchell County 765/345kV Transformer 1 37% 7% 14% 11% 6.35

Mitchell County 765/345kV Transformer 2 37% 7% 14% 11% 6.35

Mitchell County Substation 345/765 Substation14

46% 11.55

Estimated Total 40.22 16.46 0.00 0.00

14 Projects eligible to qualify for shared network upgrades must meet one of three conditions. Condition 1 requires network upgrade costs to be shared if a project connects to shared network upgrade. To determine cost share responsibility for G771, all projects eligible to share costs for the Mitchell County substation were identified, and costs well allocated on a pro rata megawatt usage.


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Table 10.2 – SPA 2011 SEMNIA Initial Drivers of Share Network Upgrade

Network Upgrade Facility Cost ($M)

Initial Funding Projects Initial Funding Cycle

Byron – North Monroe 765kV ckt1 232.80

G859, G903, H031, H033, H065, H083, H099,J001, J027, J042, J062, J077, J080, J086, J087, J087, J133, G644, G663, G668, G680, G697, G699, G721, G722, G778,G817, G818, G831, H081, G736, G821, G825, G879, G759, G763, G764, G829, G948, H016, H017, H018, H045, H052, H055, J072, J007, J045, J151, J198, G703, G704, G705, G765, G844, G857, G871, G964,G965, H011, J026, J091, J095, J139, J167, G681, G695, G735, G740, G746, G779, G855, G870, G947, G957, G962, G963, G972, H008, H028, H042, H047, J111

SPA 2008 Phase 3

Genoa – North Monroe 765kV ckt1 529.20


SPA 2008 Phase 3

Genoa 345/161 Transformer 11.80


SPA 2008 Phase 3

Mitchell County ‐ Hazelton 765 ckt 1 249.60


SPA 2008 Phase 3


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Network Upgrade Facility Cost ($M)

Initial Funding Projects Initial Funding Cycle

Mitchell County 765/345kV Transformer 1

56.4


SPA 2008 Phase 3

Mitchell County 765/345kV Transformer 2

56.4


SPA 2008 Phase 3

Mitchell County Substation

25.1


SPA 2008 Phase 3

Adams 345/161 Transformer 11.40 G871, H011, J026, J091, J095 SPA 2008 Phase 3

Adams – South Adams 161kV ckt1 0.35 H011 SPA 2008 Phase 3

Beaver Creek – Harmony 161kV ckt1 2.91 G551 CS5 Restudy

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