November 5, 2014 

Burl W. Haar 

Executive Secretary 

Minnesota Public Utilities Commission 

121 7th Place East, Suite 350 

St. Paul, Minnesota 55101-2147 

RE: Report In the Matter of the Integration and Transmission Study for the Future 

Renewable Energy Standard Required by Minnesota Law Renewable Energy Standard Required by Minnesota Laws 2013, Chapter 85 s 2013, Chapter 85, Article , Article 

12, Section 4, Directed by the Minnesota Department of Commerce Directed by the Minnesota Department of Commerce Directed by the Minnesota Department of Commerce-Division of Division of 

Energy Resources Energy Resources 

 Docket No. E999/CI-13-486 

Dear Dr. Haar: 

The Minnesota Department of Commerce-Division of Energy Resources (Department) 

provides the attached Report, as required by Minnesota Laws 2013, Chapter 85, Article 12, 

Section 4 (the Act). 

Other than accepting the report, the Minnesota Public Utilities Commission (Commission) is 

not required to take action. However, the Commission may find the information to be 

helpful in various decisions that may come before the Commission. The Department and 

the Study Team who developed the report would be willing to present the material in the 

report at a Commission Planning Meeting, if that would be helpful. In addition, the 

Department notes that there will be a webinar on the report on Thursday, November 6, 

2014, beginning at 1:30 as discussed further herein. 

The Department’s consultant, Matt Schuerger, is available to answer any questions the 

Commission may have on the report. 

Sincerely, 

/s/ WILLIAM GRANT 

Deputy Commissioner 

WG/ja 

Attachment 
1 

I. BACKGROUND BACKGROUND 

Article 12, section 4 of Minnesota Laws 2013, Chapter 85 required the Minnesota Public 

Utilities Commission (Commission) to order all electric utilities and transmission companies 

to conduct an engineering study regarding the effects on the reliability and cost of increasing 

Minnesota’s renewable energy standard (RES) to at least 40 percent by 2030, as follows: 

INTEGRATION AND TRANSMISSION STUDY FOR FUTURE 

RENEWABLE ENERGY STANDARD. RENEWABLE ENERGY STANDARD. 

(a) The commission shall order all Minnesota electric 

utilities, as defined in Minnesota Statutes, section 216B.1691, 

subdivision 1, paragraph (b), and all transmission companies, 

as defined in Minnesota Statutes, section 216B.02, to conduct 

an engineering study of the impacts on reliability and costs of, 

and to study and develop plans for the transmission network 

enhancements necessary to support, increasing the renewable 

energy standard established in Minnesota Statutes, section 

216B.1691, subdivision 2a, to 40 percent by 2030, and to 

higher proportions thereafter, while maintaining system 

reliability. 

(b) The Minnesota electric utilities and transmission 

companies must complete the study work under the direction of 

the commissioner of commerce. Prior to the start of the study, 

the commissioner, in consultation with Minnesota electric 

utilities and transmission companies, shall appoint a technical 

review committee consisting of up to 15 individuals with 

experience and expertise in electric transmission system 

engineering, electric power systems operations, and renewable 

energy generation technology to review the study's proposed 

methods and assumptions, ongoing work, and preliminary 

results. 

(c) As part of the planning process, the Minnesota electric 

utilities and transmission companies must incorporate and 

build upon the analyses that have previously been done or that 

are in progress including but not limited to the 2006 Minnesota 

Wind Integration Study and ongoing work to address 

geographically dispersed development plans, the 2007 

Minnesota Transmission for Renewable Energy Standard Study, 

the 2008 and 2009 Statewide Studies of Dispersed Renewable 

Generation, the 2009 Minnesota RES Update, Corridor, and 

Capacity Validation Studies, the 2010 Regional Generation 

Outlet Study, the 2011 Multi Value Project Portfolio Study, and 

recent and ongoing Midcontinent Independent System Operator 

transmission expansion planning work. The utilities and 

transmission companies shall collaborate with the Midcontinent 

Independent System Operator to optimize and integrate, to the 

extent possible, Minnesota's transmission plans with other 
2 

regional considerations and to encourage the Midcontinent 

Independent System Operator to incorporate Minnesota's 

planning work into its transmission expansion future planning. 

(d) The study must be completed and submitted to the 

Minnesota Public Utilities Commission by November 1, 2014. 

The report shall include a description of the analyses that have 

been conducted and the results, including: 

(1) a conceptual plan for transmission necessary for 

generation interconnection and delivery and for access to 

regional geographic diversity and regional supply and demand 

side flexibility; and 

(2) identification and development of potential solutions to 

any critical issues encountered to support increasing the 

renewable energy standard to 40 percent by 2030, and to 

higher proportions thereafter, while maintaining system 

reliability. 

This report, called the “Minnesota Renewable Energy Integration and Transmission Study” 

(MRITS), is intended to fulfill this requirement. The Minnesota Department of Commerce 

(Department) requests that the Commission accept the report. 

II. SUMMARY OF REPORT SUMMARY OF REPORT 

The Minnesota utilities and transmission companies, in coordination with the Midcontinent 

Independent System Operator (MISO), conducted the engineering study. The Department 

directed the study, conducted by a preeminent technical study team of highly skilled local, 

regional, and national engineering organizations. The utilities’ most experienced planning 

and operations engineers worked hard and constructively throughout the year to 

accomplish, in collaboration with MISO, a successful and timely completion of the study. 1 In 

addition to key personnel from Minnesota’s utilities, the team included Excel Engineering 

Inc. (power flow analysis, conceptual transmission plan), MISO (production simulation 

analysis), and GE Energy Consulting (operational performance analysis, dynamics analysis, 

mitigations and solutions, study report). 

The Department greatly appreciates all of the work by the technical review team and 

particularly appreciates Great River Energy’s (GRE) early and ongoing leadership with the 

study. 

The following are the key findings of the MRITS report: 

• The addition of wind and solar (variable renewable) generation to supply 40 

percent of Minnesota’s annual electric retail sales can be reliably accommodated 

by the electric power system. 

 

1 The Department acknowledges that the report is being filed subsequent to the November 1, 2014 due date. 

The extra days were needed to allow for final review and incorporation of edits. 
3 

• With upgrades to existing transmission, the power system can be successfully 

operated for all hours of the year (no unserved load, no reserve violations, and 

minimal curtailment of renewable energy) with wind and solar resources 

increased to achieve 40 percent renewable energy in Minnesota and with current 

renewable energy standards fully implemented in neighboring MISO 

North/Central states. 

• Further analysis would be needed to ensure system reliability at 50 percent of 

Minnesota’s annual electric retail sales from variable renewables. 

• With wind and solar resources increased to achieve 50 percent renewable energy 

in Minnesota and 25 percent renewable energy in MISO North / Central (10 

percent above current renewable energy standards in neighboring states), MRITS 

production simulation results show that, with significant transmission upgrades 

and expansions in the five state area, the power system can be successfully 

operated for all hours of the year (no unserved load, no reserve violations, and 

minimal curtailment of renewable energy). 

• Due to study schedule limitations, no dynamic analysis was performed for 50 

percent renewable energy in Minnesota; such analysis would be necessary to 

ensure system reliability. 

III. RECOMMENDED NEXT STEPS RECOMMENDED NEXT STEPS 

This MRITS report does not requires action by the Commission. However, the report may 

provide helpful information in proceedings that may come before the Commission. The 

Department and the Study Team who developed the report would be willing to present the 

material in the report at a Commission Planning Meeting, if that would be helpful. 

In addition, there will be a webinar on the report on Thursday, November 6, 2014, beginning 

at 1:30. Registration is at: https://www1.gotomeeting.com/register/314429457

/ja 
 GE Energy Consulting

Minnesota Renewable Energy 

Integration and Transmission 

Study 

Final Report 

Prepared for:

 The Minnesota Utilities and Transmission Companies

 The Minnesota Department of Commerce

Prepared by:

 GE Energy Consulting, with contributions by:

– The Minnesota Utilities and Transmission Companies

– Excel Engineering, Inc.

– MISO

In Collaboration with MISO

October 31, 2014
GE Energy Consulting MRITS Final Report

Legal Notice i

Legal Notices

This report was prepared by General Electric International, Inc. (GE) as an account of work 

sponsored by Great River Energy which was serving as a representative of the Minnesota Utilities 

and Transmission Companies. Neither Great River Energy nor GE, nor any person acting on behalf 

of either:

1. Makes any warranty or representation, expressed or implied, with respect to the use of any 

information contained in this report, or that the use of any information, apparatus, method, 

or process disclosed in the report may not infringe privately owned rights.

2. Assumes any liabilities with respect to the use of or for damage resulting from the use of any 

information, apparatus, method, or process disclosed in this report.
October 31, 2014

In 2013 the Minnesota Legislature adopted a requirement for a Renewable Energy Integration 

and Transmission Study1 (MRITS). MRITS is an engineering study of increasing the Minnesota 

Renewable Energy Standard to 40% by 2030, and to higher proportions thereafter, while 

maintaining system reliability. 

Background. MRITS builds upon prior renewable integration studies and related technical 

work and is coordinated with recent and current regional power system study work. Over 

summer 2013, Commerce reviewed prior and current related studies and worked with 

stakeholders and study participants to identify key issues. In fall 2013, Commerce held a 

stakeholder meeting to discuss the objectives, scope, schedule, and process. The study began 

in November 2013 and was completed in October 2014. 

Study details. MRITS is focused on the reliability impacts of increased levels of variable

renewables (wind and solar generation) and the associated costs of those impacts. The study 

scope was developed from statutory guidance, stakeholder input, and technical study team 

refinement. MRITS incorporates three core and interrelated analyses: 1) Power flow analysis

for development of a conceptual transmission plan, which includes transmission necessary for 

generation interconnection and delivery and for access to regional geographic diversity and 

system flexibility; 2) Production simulation analysis which evaluates hour-by-hour operational 

performance for an entire year, including reserve violations, unserved load, wind / solar 

curtailments, thermal cycling, and ramp rate and ramp range, and, to screen for challenging time 

periods; and 3) Dynamics analysis, which includes transient stability analysis and weak system 

strength analysis. The broad study scope and the aggressive schedule have been very 

significant challenges.

Technical team. The MN utilities and transmission companies, in coordination with MISO, 

conducted the engineering study. The Department of Commerce directed the study. The 

Minnesota utilities and transmission companies engaged early in the study development and, 

through the active participation of the companies’ most experienced planning and operations 

engineers, worked hard and constructively throughout the year to accomplish, in collaboration 

with MISO, a successful and timely completion of the study. A preeminent technical study team 

of highly skilled local, regional, and national engineering organizations was assembled to work 

collaboratively on the analysis. This included major contributions from the Minnesota utilities 

and transmission companies (siting, conceptual transmission plan), Excel Engineering Inc (power 

flow analysis, conceptual transmission plan), MISO (production simulation analysis), and GE 

1 MN Laws 2013, Chapter 85 HF 729, Article 12, Section 4; MPUC Docket No. CI-13-486.

 
Energy Consulting (operational performance analysis, dynamics analysis, mitigations and 

solutions, study report). Great River Energy (GRE) provided key early and ongoing study 

leadership. GRE’s Gordon Pietsch organized and coordinated full participation by the Minnesota 

utilities and transmission companies and GRE’s Jared Alholinna led the technical study team –

both worked tirelessly and effectively to ensure the best, most knowledgeable, most experienced 

engineers were organized, funded, focused, and coordinated throughout the study.

Study review. The study has greatly benefited from extensive ongoing review and guidance by 

an expert Technical Review Committee (TRC). The Department of Commerce appointed and led 

the TRC, which included engineers with experience and expertise in electric transmission system 

engineering, electric power system operations, and renewable energy generation technology. 

Seven TRC meetings, four full day and three half day, were held throughout the course of the 

study to review and discuss the study methods and assumptions, scenarios, model 

development, results, and key findings. With excellent input from the utilities and transmission 

companies, MISO, renewables specialists, and national experts, consensus was reached on 

overall study methods and assumptions, on the scenarios to be studied, on the modeling 

approach, and on the results and key findings.

Key findings. The analytical results from this study show that the addition of wind and solar 

(variable renewable) generation to supply 40% of Minnesota’s annual electric retail sales can be 

reliably accommodated by the electric power system. The MRITS operational and dynamics 

analyses results show that, with upgrades to existing transmission, the power system can be 

successfully operated for all hours of the year (no unserved load, no reserve violations, and 

minimal curtailment of renewable energy) with wind and solar resources increased to achieve 

40% renewable energy in Minnesota and with current renewable energy standards fully 

implemented in neighboring MISO North/Central states. Further analysis would be needed to 

ensure system reliability at 50% of Minnesota’s annual electric retail sales from variable 

renewables. With wind and solar resources increased to achieve 50% renewable energy in 

Minnesota and 25% renewable energy in MISO North / Central (10% above current renewable 

energy standards in neighboring states), MRITS production simulation results show that, with 

significant transmission upgrades and expansions in the five state area, the power system can be 

successfully operated for all hours of the year (no unserved load, no reserve violations, and 

minimal curtailment of renewable energy). Due to study schedule limitations, no dynamic 

analysis was performed for 50% renewable energy in Minnesota (Scenarios 2 and 2a) and this 

analysis is necessary to ensure system reliability. 

Thank you to all of the study participants for an extraordinary and collaborative effort and for 

successful completion of a ground breaking study.

Sincerely,

William Grant

Deputy Commissioner, Division of Energy Resources
GE Energy Consulting MRITS Final Report

Technical Study Team iii

Technical Study Team

Jared Alholinna, P.E. (Great River Energy) – Technical Study Team Lead

GE Energy Consulting (GE) – operating performance, dynamics, mitigations / solutions

Douglas Welsh Durga Gautam Robert D'Aquila

Richard Piwko Eknath Vittal Slobodan Pajic

Gary Jordan Nicholas Miller

Excel Engineering, Inc. – power flow analysis, transmission conceptual plan

Michael Cronier, P.E. LaShel Marvig, P.E.

MISO – technical coordination, models, data; production simulation analysis

Jordan Bakke Brandon Heath Cody Doll

Aditya Jayam Prabhakar

Technical Study Team participants – weekly coordination calls, ongoing technical study participation 

with Excel Engineering, General Electric and MISO.

Kevin Demeny American Transmission Company

Steve Porter, P.E. Dairyland Power Cooperative

Richa Singhal Great River Energy

Jeff Eddy ITC Midwest

David Jacobson Manitoba Hydro

Scott Hoberg, P.E. Minnesota Power

Andrew Kienitz Minnesota Power

George Sweezy, P.E. Minnesota Power

Christian Winter, P.E Minnesota Power

Aaron Vander Vorst, P.E. Minnkota Power Cooperative

John Weber Missouri River Energy Services

Matt Schuerger, P.E. MN Department of Commerce

Lise Trudeau MN Department of Commerce

Michael Riewer Otter Tail Power

Jason Weiers, P.E. Otter Tail Power

Andrew Lucero, P.E Representing CMMPA

Steve Beuning Xcel Energy

Jarred Cooley Xcel Energy

Amanda King Xcel Energy

Dean Schiro, P.E. Xcel Energy
GE Energy Consulting MRITS Final Report

Technical Review Committee iv

Technical Review Committee (TRC)

Representing

Mark Ahlstrom, CEO Wind Logics 

Steve Beuning, Director Market Operations Xcel Energy 

Jeff Eddy, Manager Planning ITC Holdings

Brendan Kirby, Consultant, Grid Integration & Reliability NREL

Mark Mitchell, Director of Operations and COO SMMPA 

Michael Milligan, Principal Researcher, Grid Integration NREL 

Dale Osborn, Consulting Advisor, Policy & Economic 

Studies MISO 

Rhonda Peters, Principal, InterTran Energy Wind on the Wires

Gordon Pietsch, Director Transmission Planning & 

Operations Great River Energy 

Larry Schedin, P.E., Principal, LLS Resources MN Chamber of Commerce 

Dean Schiro, P.E., Manager Real Time Planning Xcel Energy 

Matt Schuerger, P.E., - Technical Advisor - TRC Chair MN Department of Commerce 

Glen Skarbakka, P.E., Consultant Skarbakka LLC 

Charlie Smith, Executive Director Utility Variable Generation Integration Group 

George Sweezy .P.E., Manager System Performance &

Planning Minnesota Power 

Jason Weiers, P.E., Manager Delivery Planning Otter Tail Power 

Terry Wolf, Manager Transmission Services Missouri River Energy Services 

Observers

Cezar Panait, P.E., Regulatory Engineer MN Public Utilities Commission

Lise Trudeau, Engineer MN Department of Commerce
GE Energy Consulting MRITS Final Report

TABLE OF CONTENTS

1 EXECUTIVE SUMMARY .............................................................................................................1-1

1.1 Background ......................................................................................................................1-1

1.2 Study Objectives and Overall Approach .....................................................................1-2

1.3 Development of Study Scenarios .................................................................................1-3

1.4 Development of Transmission Conceptual Plans......................................................1-4

1.5 Evaluation of Operational Performance .....................................................................1-4

1.6 Dynamic Performance Analysis....................................................................................1-5

1.7 Key Findings .....................................................................................................................1-6

1.7.1 General Conclusions for 40% RE Penetration in Minnesota........................................ 1-6

1.7.2 General Conclusions for 50% RE Penetration in Minnesota........................................ 1-7

1.7.3 Annual Energy in the Minnesota-Centric Region........................................................... 1-7

1.7.4 Cycling of Thermal Plants................................................................................................... 1-8

1.7.5 Curtailment of Wind and Solar Energy ............................................................................ 1-9

1.7.6 Other Operational Issues .................................................................................................1-10

1.7.7 System Stability, Voltage Support, Dynamic Reactive Reserves ..............................1-10

1.7.8 Weak System Issues ..........................................................................................................1-11

1.7.9 Mitigations ..........................................................................................................................1-12

2 PROJECT OVERVIEW ...............................................................................................................2-1

2.1 Background ......................................................................................................................2-1

2.2 Objectives .........................................................................................................................2-1

2.3 Study Timeline..................................................................................................................2-2

2.4 Study Scope ......................................................................................................................2-2

2.5 Study Scenarios ...............................................................................................................2-5

3 WIND AND SOLAR GENERATION SITING .............................................................................3-1

3.1 Siting for Wind Resources..............................................................................................3-2

3.1.1 Minnesota Wind ................................................................................................................... 3-3

3.1.2 MISO (non-MN) Wind ........................................................................................................... 3-3

3.2 MISO Wind Reassignment..............................................................................................3-9

3.3 Siting of PV Solar Resources....................................................................................... 3-11

3.3.1 Minnesota PV Solar............................................................................................................3-11

3.3.2 Non-Minnesota PV Solar...................................................................................................3-16
GE Energy Consulting MRITS Final Report

4 TRANSMISSION SYSTEM CONCEPTUAL PLANS ...................................................................4-1

4.1 Study Assumptions and Methodology.........................................................................4-1

4.1.1 Study Procedure................................................................................................................... 4-1

4.1.2 Models Employed ................................................................................................................. 4-2

4.1.3 Baseline Model...................................................................................................................... 4-4

4.1.4 S1 Model (Added beyond Baseline) ................................................................................. 4-4

4.1.5 S2 Model (Added beyond S1) ............................................................................................. 4-5

4.2 Results ...............................................................................................................................4-5

4.2.1 SCED /MISO Footprint ......................................................................................................... 4-5

4.2.2 Scenario 2............................................................................................................................4-12

4.3 Conceptual Transmission Conclusions .................................................................... 4-21

5 DYNAMIC SIMULATION MODEL.............................................................................................5-1

5.1 Data Sources and Benchmarking of Dynamic Models .............................................5-1

5.2 Dynamic Load Model ......................................................................................................5-2

5.3 2028 Study Data Sets......................................................................................................5-4

5.4 Dynamic Models for Renewables .................................................................................5-4

5.5 Monitoring Models and Performance Metrics ...........................................................5-5

6 PRODUCTION SIMULATION MODEL .....................................................................................6-1

6.1 Overview of Production Simulations ...........................................................................6-1

6.2 PLEXOS Overview.............................................................................................................6-1

6.3 MRITS Production Simulation Model – Source Dataset............................................6-1

6.3.1 Baseline Scenario................................................................................................................. 6-5

6.3.2 Scenarios 1 and 2................................................................................................................. 6-5

6.3.3 Capacity Credit for Wind and Solar Resources .............................................................. 6-6

6.3.4 Forecast Uncertainty........................................................................................................... 6-8

7 OPERATIONAL PERFORMANCE RESULTS.............................................................................7-1

7.1 Scenarios for Production Simulation Analysis...........................................................7-1

7.2 Annual Energy..................................................................................................................7-2

7.2.1 Aggregate Wind and Solar Plant Capacity and Power Output ................................... 7-7

7.2.2 Comparisons of Generation Fleet Utilization for Study Scenarios ............................. 7-9

7.3 Wind and Solar Curtailment....................................................................................... 7-12

7.4 Thermal Plant Cycling.................................................................................................. 7-15

7.4.1 Coal Units ............................................................................................................................7-15

7.4.2 Combined-Cycle Units.......................................................................................................7-19
GE Energy Consulting MRITS Final Report

7.5 MISO Ramp-Range and Ramp-Rate Capability....................................................... 7-19

7.6 Carbon Emissions......................................................................................................... 7-23

7.7 Screening Metrics for Stability/Control Issues ....................................................... 7-23

7.7.1 Percent Non-Synchronous Generation (% NS).............................................................7-23

7.7.2 Percent Renewable Penetration (% RE).........................................................................7-25

7.7.3 Transmission Interface Loading .....................................................................................7-25

7.7.4 Analysis of Percent Non-Synchronous Generation .....................................................7-27

7.7.5 Percent Renewable Penetration Analysis .....................................................................7-31

7.7.6 Transmission Interface Loading .....................................................................................7-32

7.8 Selection of Operating Conditions for Dynamic Analysis..................................... 7-34

8 DYNAMIC SIMULATION RESULTS ..........................................................................................8-1

8.1 Dynamic Performance Study Conditions....................................................................8-1

8.2 Voltage Regulation & Stability Analysis ......................................................................8-9

8.2.1 Disturbances......................................................................................................................... 8-9

8.2.2 Overall Results....................................................................................................................8-10

8.2.3 High % NS conditions........................................................................................................8-11

8.2.4 High %RE conditions.........................................................................................................8-18

8.2.5 High Transfer Conditions..................................................................................................8-19

8.3 Reactive Reserves ........................................................................................................ 8-25

8.4 Weak Grid Analysis ...................................................................................................... 8-26

8.4.1 Composite Short Circuit Ratio Concepts .......................................................................8-26

8.4.2 Identifying Weak Regions.................................................................................................8-28

8.4.3 Southwestern Minnesota CSCR.......................................................................................8-29

8.4.4 Mitigation through Wind/PV Inverter Controls............................................................8-30

8.4.5 Low CSCR Mitigation..........................................................................................................8-30

9 KEY FINDINGS...........................................................................................................................9-1

9.1 General Conclusions for 40% RE Penetration in Minnesota...................................9-1

9.2 General Conclusions for 50% RE Penetration in Minnesota...................................9-1

9.3 Annual Energy in the Minnesota-Centric Region ......................................................9-2

9.4 Cycling of Thermal Plants ..............................................................................................9-3

9.5 Curtailment of Wind and Solar Energy........................................................................9-4

9.6 Other Operational Issues...............................................................................................9-5

9.7 System Stability, Voltage Support, Dynamic Reactive Reserves............................9-5

9.8 Weak System Issues........................................................................................................9-6
GE Energy Consulting MRITS Final Report

9.9 Mitigations........................................................................................................................9-7

10 REFERENCES .......................................................................................................................... 10-1

11 Appendices ............................................................................................................................ 11-1
GE Energy Consulting MRITS Final Report

LIST OF FIGURES

Figure 1-1 Annual Energy by Type in Minnesota-Centric Region for Study Scenarios ........1-8

Figure 2-1 Flowchart of Project Tasks ....................................................................................................2-4

Figure 3-1 RGOS Wind Zones.....................................................................................................................3-4

Figure 3-2 MN & Non MN Scenario 1 Wind Siting ..............................................................................3-8

Figure 3-3 RGOS Wind Zones w/MN & Non MN Scenario 2............................................................3-9

Figure 3-4 Wind Shift from the 4 Most-Congested to the 10 Least-Congested Sites........ 3-10

Figure 3-5 United States Photovoltaic Solar Resource (portion of) .......................................... 3-12

Figure 3-6 MN Solar for Utility Locations - Baseline....................................................................... 3-14

Figure 3-7 MN Solar for Utility Locations - All Scenarios.............................................................. 3-14

Figure 3-8 MN Distributed PV Sites....................................................................................................... 3-16

Figure 3-9 Locations of Non-MN Solar - Utility Locations............................................................ 3-19

Figure 4-1 Bus Angles from MRITS2028-S70-R17-Basea SCED Model.......................................4-7

Figure 4-2 Bus Angles from MRITS2028-S70-R20-S1 Model0........................................................4-8

Figure 4-3 S1 Transmission Mitigation Map...................................................................................... 4-11

Figure 4-4 Bus Angles from MRITS2028-S70-R19-S2 Model....................................................... 4-12

Figure 4-5 S2 Transmission Expansion Map ..................................................................................... 4-13

Figure 4-6 Bus Angles from MRITS2028-S70-R19-S2-Trans Model.......................................... 4-14

Figure 4-7 Bus Angles from MRITS2028-S70-R19-S2-Trans-R2-SCED-A-T4B10 Model.... 4-15

Figure 4-8 Transmission Mitigation Map............................................................................................ 4-17

Figure 4-9 Map of S2 Transmission Mitigations from Production Cost Analysis................. 4-18

Figure 4-10 HVDC Transmission Map.................................................................................................. 4-19

Figure 5-1 GE PSLF Composite Load Model CMPLDW......................................................................5-3

Figure 5-2 Renewable generation topology in powerflow Model................................................5-5

Figure 5-3 Geographical subregions ......................................................................................................5-6

Figure 5-4 Voltage performance metrics..............................................................................................5-8

Figure 6-1 Study Footprint..........................................................................................................................6-2

Figure 6-2 MISO’s Market Footprint.........................................................................................................6-2

Figure 6-3 State Renewable Portfolio Standard Policies used in the MTEP13 Model...........6-3

Figure 6-4 MISO’s MTEP13 BAU capacity additions and coal Retirements ..............................6-4

Figure 6-5 Illustration of site specific renewable output.................................................................6-5

Figure 6-6 Resource Capacity Changes for Scenarios 1 and 2.....................................................6-6

Figure 6-7 Plot of Wind Capacity Credit versus Penetration Level, from MISO Report........6-7

Figure 6-8 Scatter Plot of Wind versus Solar Output...........................................................................6-8

Figure 6-9 Sample of Hourly Forecast and Actual Wind Site Output (1st week of July) ......6-9

Figure 6-10 Sample of Hourly Forecast and Actual Solar Site Output (1st week of July)).. 6-10

Figure 6-11 Sample Minnesota Load Output (1st week of July).................................................. 6-11

Figure 7-1 Minnesota-Centric footprint for production simulation (Plexos) Analysis...........7-2

Figure 7-2 Annual generation in TWh by unit type for Minnesota-Centric region ................7-4
GE Energy Consulting MRITS Final Report

Figure 7-3 Annual Committed Capacity and Dispatch Energy .....................................................7-5

Figure 7-4 Annual Load and Net Load Duration Curves for Minnesota-Centric Region.....7-6

Figure 7-5 Annual Duration Curves of Energy Imports for Minnesota-Centric Region........7-7

Figure 7-6 Duration Curves of Aggregate Wind Plant Capacity...................................................7-8

Figure 7-7 Duration Curves of Aggregate Solar Plant Capacity...................................................7-8

Figure 7-8 Annual Duration Curves of Solar Curtailment for Minnesota-Centric Region 7-13

Figure 7-9 Annual Duration Curves of Wind Curtailment for Minnesota-Centric Region 7-14

Figure 7-10 Wind Curtailment by Hour of Day for Minnesota-Centric Region .................... 7-14

Figure 7-11 Coal Unit Total Annual Starts for Baseline, Scenario 1 and Scenario 2.......... 7-16

Figure 7-12 Coal Unit Total Annual Starts for Scenario 1 and Scenario 1a .......................... 7-17

Figure 7-13 Coal Unit Total Annual Starts for Scenario 2 and Scenario 2a .......................... 7-17

Figure 7-14 Coal Unit Total Annual Starts for Scenario 1a and Scenario 2a........................ 7-18

Figure 7-15 Coal Unit Annual “Operational” Starts due to Economic Commitment.......... 7-18

Figure 7-16 Combined-Cycle Unit Total Annual Starts ................................................................. 7-19

Figure 7-17 Annual Duration Curve of Range-Up Capability...................................................... 7-20

Figure 7-18 Annual Duration Curve of Ramp-Rate-Up Capability............................................ 7-20

Figure 7-19 Annual Duration Curve of Range-Down Capability................................................ 7-21

Figure 7-20 Annual Duration Curve of Ramp-Rate-Down Capability...................................... 7-21

Figure 7-21 Scatter Plot of Ramp-Rate Down Capability............................................................. 7-22

Figure 7-22 Geographic Footprint of Minnesota-Centric Region for % NS Metric ............. 7-24

Figure 7-23 NDEX Transmission Interface......................................................................................... 7-25

Figure 7-24 Buffalo Ridge Outlet Lines................................................................................................ 7-26

Figure 7-25 MWEX Transmission Interface ....................................................................................... 7-27

Figure 7-26 Baseline % NS Duration Curves..................................................................................... 7-28

Figure 7-27 Scenario 1 % NS Duration Curves ................................................................................ 7-28

Figure 7-28 Scenario 1 (solid) and 1a (dashed) % NS Duration Curves .................................. 7-29

Figure 7-29 Scenario 2 % NS Duration Curves ................................................................................ 7-29

Figure 7-30 Scenario 2 (solid) and 2a (dashed) % NS Duration Curves .................................. 7-30

Figure 7-31 % RE Penetration for the Minnesota-Centric Region ............................................ 7-31

Figure 7-32 NDEX Total Loading for Scenario 1 and Scenario 1a............................................. 7-32

Figure 7-33 Buffalo Ridge Outlet Loading for Scenario 1 and Scenario 1a........................... 7-33

Figure 7-34 MWEX Total Loading for Scenario 1 and Scenario 1a........................................... 7-33

Figure 7-35 Load Duration Curve and % NS for the Minnesota-Centric Region................. 7-34

Figure 7-36 Chronological Load and % NS for the Minnesota-Centric Region ................... 7-35

Figure 7-37 Filtered Load and % NS to the Fall Shoulder-Load Window............................... 7-36

Figure 7-38 Further Filter Fall Shoulder Hours for Scenario 1 Stability Analysis................. 7-37

Figure 7-39 NDEX Interface Screening for Scenario 1 and Scenario 1a................................. 7-39

Figure 7-40 Buffalo Ridge Outlet Interface Screening for Scenario 1 and Scenario 1a ... 7-39

Figure 7-41 MWEX Interface Screening for Scenario 1 and Scenario 1a............................... 7-40

Figure 7-42 Case 2 Stability Screening for Scenario 1 and Scenario 1a ................................ 7-40
GE Energy Consulting MRITS Final Report

Figure 8-1 Minnesota Centric Dispatch (MW) By Unit Type...........................................................8-4

Figure 8-2 Minnesota Centric Percentage Generation Dispatch by Type..................................8-5

Figure 8-3 Minnesota Centric Commitment (MVA) by Unit Type ....................................................8-6

Figure 8-4 Percentage of On-line Non- vs Synchronous MVA..........................................................8-6

Figure 8-5 Percentage of online, non- and synchronous MVA by Sub-Region......................8-7

Figure 8-6 Online MVA of synchronous and non-synch Generation by Region ....................8-8

Figure 8-7 Dynamic Reactive Reserves of synchronous and non-synch Generation..........8-8

Figure 8-8 Case 1: Terminal King Fault Active and Reactive Response................................ 8-12

Figure 8-9 Case 1: Terminal King fault Voltage Magnitude........................................................ 8-13

Figure 8-10 Case 2: Trip DEERCK fault Active and Reactive Response .................................. 8-14

Figure 8-11 Case 2: Trip DEERCK fault Voltage Magnitude ........................................................ 8-15

Figure 8-12 Case 3: AG3 fault Active and Reactive Response................................................... 8-16

Figure 8-13 Case 3: AG3 fault Voltage Magnitude......................................................................... 8-17

Figure 8-14 Case 4: NAD fault Active and Reactive Response.................................................. 8-18

Figure 8-15 Case 4: NAD fault Voltage Magnitude........................................................................ 8-19

Figure 8-16 Case 5: AG1_v2 fault Active and Reactive Response ........................................... 8-20

Figure 8-17 Case 5: AG1_v2 fault Voltage Magnitude ................................................................. 8-21

Figure 8-18 Case 6: SHEAS fault Active and Reactive Response.............................................. 8-22

Figure 8-19 Case 6: SHEAS fault Voltage Magnitude.................................................................... 8-23

Figure 8-20 Case 7: BRIGGS fault Active and Reactive Response............................................ 8-24

Figure 8-21 Case 7: BRIGGS fault Voltage Magnitude.................................................................. 8-25

Figure 8-22 Example of composite, short-circuit MVA at Multiple Wind Plants................. 8-27

Figure 8-23 SC MVA vs. Voltage Regulation Ratio ......................................................................... 8-29

Figure 9-1 Annual Energy by Type in Minnesota-Centric Region for Study Scenarios ........9-3

LIST OF TABLES

Table 1-1 Study Scenarios..........................................................................................................................1-3

Table 1-2 Wind and Solar Curtailment for Study Scenarios......................................................... 1-10

Table 2-1 Wind and Solar Resource Allocations for Study Scenarios ........................................2-6

Table 3-1 Minnesota-Centric Wind and Solar Amounts to be Sited............................................3-1

Table 3-2 Non-MN-Centric Wind and Solar Amounts to be Sited................................................3-1

Table 3-3 Key assumptions for Wind & Solar Build-Outs ................................................................3-2

Table 3-4 MISO Wind Locations-Baseline .............................................................................................3-5

Table 3-5 Incremental Minnesota-Centric Wind Locations for Scenarios 1&2.......................3-6

Table 3-6 Minnesota-Centric Wind Siting .............................................................................................3-6

Table 3-7 Non Minnesota MISO Wind Locations- Scenario 1 & 2 ................................................3-7

Table 3-8 Non-MN MISO Wind Siting ......................................................................................................3-8

Table 3-9 Wind Shift from the 4 Most-Congested to the 10 Least-Congested Sites ......... 3-10
GE Energy Consulting MRITS Final Report

Table 3-10 Minnesota Utility PV Sites for Study Scenarios .......................................................... 3-13

Table 3-11 MN Distributed PV Sites for Study Scenarios.............................................................. 3-15

Table 3-12 Non-MN Solar for Utility Locations................................................................................. 3-17

Table 3-13 Non-MN Distributed Solar for Study Scenarios ......................................................... 3-18

Table 4-1 S1 Transmission Mitigation.....................................................................................................4-9

Table 4-2 S2 Transmission Expansion................................................................................................. 4-13

Table 4-3 S2 Transmission Mitigation.................................................................................................. 4-16

Table 4-4 S2 Transmission Mitigations from Production Cost Analysis.................................. 4-18

Table 4-5 S2 AC Transmission Mitigations required with HVDC Option ................................. 4-20

Table 4-6 Scenario Transmission Cost Breakdown........................................................................ 4-22

Table 5-1 Benchmark Contingencies......................................................................................................5-2

Table 5-2 Non-industrial Load Types......................................................................................................5-3

Table 5-3 Industrial Load Types................................................................................................................5-4

Table 5-4 Sub region assignment ............................................................................................................5-7

Table 7-1 Study Scenarios ..........................................................................................................................7-1

Table 7-2 Major Assumptions for Production Simulation Analysis of Study Scenarios .......7-1

Table 7-3 Annual Load, Wind and Solar Energy for Minnesota-Centric Region.....................7-3

Table 7-4 Comparison of Minnesota-Centric Generation Fleet Utilization............................ 7-10

Table 7-5 Comparison of Minnesota-Centric Generation Fleet Utilization............................. 7-11

Table 7-6 Annual Wind and Solar Energy Curtailment ................................................................. 7-13

Table 7-7 CO2 Emissions for the Minnesota-Centric Region....................................................... 7-23

Table 7-8 Maximum and Minimum % NS Values ............................................................................ 7-30

Table 7-9 Stability Cases for Scenario 1 ............................................................................................. 7-38

Table 8-1 Stability Case Description ......................................................................................................8-2

Table 8-2 Fault Description for Stability Analysis.................................................................................8-9

Table 8-3 Transient Stability Analysis Results .................................................................................. 8-10

Table 8-4 S1 Renewable Generation in SW Minnesota (Total MW Rating) ........................... 8-32

Table 9-1 Wind and Solar Curtailment for Study Scenarios............................................................9-5
GE Energy Consulting MRITS Final Report

NOMENCLATURE 1

Nomenclature

BAU Business as Usual

CC or CCGT Combined Cycle Gas Turbine

CEMS Continuous Emissions Monitoring Systems

CF Capacity Factor

CO2 Carbon Dioxide

CSCR Composite Short-Circuit Ratio

CV Capacity Value

DA Day-Ahead

DIR Dispatchable Intermittent Resource

DPV Distributed Photovoltaic Generation Resource

DR Demand Response

DSM Demand Side Management

EI Eastern Interconnection

EMTP Electro-Magnetic Transients Program

ERGIS Eastern Renewable Generation Integration Study (by NREL)

EWITS Eastern Wind Integration and Transmission Study (by NREL)

FERC Federal Energy Regulatory Commission

GE General Electric International, Inc. / GE Energy Consulting

GT Gas Turbine

GW Gigawatt

GWh Gigawatt Hour

HA Hour Ahead

HVDC High-Voltage Direct-Current

kV kilovolt

kW kilowatt

kWh kilowatt-hour

LBA Local Balancing Authority

LMP Locational Marginal Prices

MRITS Minnesota Renewable Energy Integration and Transmission Study

MTEP MISO Transmission Expansion Plan

MVA Megavolt Ampere

MVP Multi-Value Project

MW Megawatts

MWh Megawatt Hour

NERC North American Electric Reliability Corporation
GE Energy Consulting MRITS Final Report

NOMENCLATURE 2

Nomenclature

NOx Nitrogen Oxides

NREL National Renewable Energy Laboratory

NS Non-Synchronous

O&M Operation & Maintenance

PJM PJM Interconnection, LLC.

POI Point of Interconnection

PPA Power Purchase Agreement

PSCAD Manitoba HVDC Research Centre’s Electro-Magnetic Transients 

Simulation program (Power System Computer Aided Design)

PSH Pumped Storage Hydro

PV Photovoltaic

RE Renewable Energy

REC Renewable Energy Credit

RES Renewable Energy Standard

RGOS Regional Generation Outlet Study

RPS Renewable Portfolio Standard

SCED Security Constrained Economic Dispatch

SCR Short-Circuit Ratio

SCUC Security Constrained Unit Commitment

SES Solar Energy Standard

SOx Sulfur Oxides

ST Steam Turbine

STATCOM Static Compensator

SVC Static Var Compensator

TPL NERC’s Transmission Planning Standard

TRC Technical Review Committee

TWh Terawatt Hour (1000 Megawatt hours)

VOC Variable Operating Cost

WTG Wind Turbine-Generator

ZVRT Zero-Voltage Ride-Through
GE Energy Consulting MRITS Final Report

EXECUTIVE SUMMARY 1-1

1 EXECUTIVE SUMMARY

1.1 Background

In 2013 the Minnesota Legislature adopted a requirement for a Renewable Energy Integration and 

Transmission Study1(MRITS). The MN utilities and transmission companies, in coordination with

MISO, conducted the engineering study. The Department of Commerce directed the study and 

appointed and led the Technical Review Committee (TRC). It is an engineering study of increasing 

the Minnesota Renewable Energy Standard to 40% by 2030, and to higher proportions thereafter, 

while maintaining system reliability. The final study includes: 1) A conceptual plan for transmission 

for generation interconnection and delivery and for access to regional geographic diversity and 

regional supply and demand side flexibility, and 2) Identification and development of potential 

solutions to any critical issues encountered. 

All utilities with Minnesota retail electric sales and all Minnesota transmission companies 

participated and/or were represented in the study. Eight Minnesota Local Balancing Authorities are 

represented and over 85% of the Minnesota retail sales are in the four largest Local Balancing 

Authorities (LBA): Xcel Energy (NSP), Great River Energy, Minnesota Power, and Otter Tail Power. The 

study area is within the NERC reliability region Midwest Reliability Organization (MRO). Nearly all of 

the Minnesota retail sales are within the Midcontinent Independent System Operator (MISO). The 

Local Balancing Authorities within MISO, including the Minnesota LBAs, are functionally 

consolidated.

Prior studies of relevance include the 2006 Minnesota Wind Integration Study2, the 2007 Minnesota 

Transmission for Renewable Energy Standard Study3, the 2009 Minnesota RES Update, Corridor, and 

Capacity Validation Studies, the 2008 and 2009 Statewide Studies of Dispersed Renewable 

Generation4, the 2010 Regional Generation Outlet Study, the 2011 Multi Value Project Portfolio 

Study, the 2013 Minnesota Biennial Transmission Project Report5, the 2013 MISO Transmission 

Expansion Plan, and recent and ongoing MISO transmission expansion planning work6.

 

1 MN Laws 2013, Chapter 85 HF 729, Article 12, Section 4; MPUC Docket No. CI-13-486.

2

2006 MN Wind Integration Study. Prepared for the MPUC, Nov 2006. 

 Final Report Volumes I & II, Final Report Presentation. http://www.puc.state.mn.us/PUC/electricity/013752 

3

“Minnesota RES Update Study Technical Report.” March 2009. “RES Transmission Report.” November 2007.

 “Southwest Twin Cities – Granite Falls Transmission Upgrade Study Technical Report.” March 2009.

 “Capacity Validation Study Report.” March 2009. http://www.minnelectrans.com/reports.html

4 Dispersed Renewable Generation Studies. June 2008 and September 2009. 

http://mn.gov/commerce/energy/topics/resources/Reports-Data/Energy-Reports.jsp

5

http://www.minnelectrans.com/, November 1, 2013.

6

https://www.misoenergy.org/Planning/TransmissionExpansionPlanning/Pages/TransmissionExpansionPlanning.aspx
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EXECUTIVE SUMMARY 1-2

1.2 Study Objectives and Overall Approach

The study objectives are listed below.

1. Evaluate the impacts on reliability and costs associated with increasing Renewable Energy 

to 40% of Minnesota retail electric energy sales by 2030, and to higher proportions 

thereafter; 

2. Develop a conceptual plan for transmission necessary for access to regional geographic 

diversity and regional system flexibility;

3. Identify and develop options to manage the impacts of the renewable energy resources;

4. Build upon prior wind integration studies and related technical work; Coordinate with recent 

and current regional power system study work;

5. Produce meaningful, broadly supported results through a technically rigorous, inclusive 

study process.

This study is focused on the reliability impacts of increased levels of variable renewables (wind and 

solar generation) and the associated costs of those impacts.

MRITS builds upon prior wind integration studies and related technical work and is coordinated with 

recent and current regional power system study work. The study scope was developed from 

statutory guidance, stakeholder input, and technical study team refinement. 

MRITS incorporates three core and interrelated analyses: 1) Power flow analysis for development of 

a conceptual transmission plan, which includes transmission necessary for generation 

interconnection and delivery and for access to regional geographic diversity and regional supply 

and demand side flexibility; 2) Production simulation analysis for evaluation of operational 

performance, including reserve violations, unserved load, wind / solar curtailments, thermal cycling, 

and ramp rate and ramp range, and, to screen for challenging time periods; and 3) Dynamics 

analysis, which includes transient stability analysis and weak system strength analysis. 

The MRITS study area is Minnesota-centric, which focuses on the combined operating areas of the 

Minnesota utilities and transmission companies, in the context of the MISO North/Central areas and 

the neighboring regions to the west and north. 

The base study models (baseline and scenarios) are coordinated with and consistent with MISO 

models and databases including dispatch to the MISO market. Additional options were considered 

in Task 7 (Identify & Develop Mitigations / Solutions) as needed.

The key study tasks are:

 Develop Study Scenarios; Site Wind and Solar Generation (Lead contributors: Minnesota Utilities; 

Minnesota Department of Commerce)

 Perform Production Simulation Analysis (Lead Contributor: MISO)

 Perform Power Flow Analysis; Develop Transmission Conceptual Plan (Lead Contributors: 

Minnesota Utilities & Transmission Owners; Excel Engineering)

 Evaluate Operational Performance (Lead Contributor: GE Energy Consulting)
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EXECUTIVE SUMMARY 1-3

 Screen for Challenging Periods (Lead Contributor: GE Energy Consulting)

 Evaluate stability related issues, including transient stability performance, voltage regulation 

performance, adequacy of dynamic reactive support, and weak system strength issues (Lead 

Contributor: GE Energy Consulting) 

 Identify and Develop Mitigations and Solutions (Lead Contributor: GE Energy Consulting)

1.3 Development of Study Scenarios

The Baseline scenario has sufficient renewable energy generation to satisfy the current renewable 

energy standards and solar energy standards for all states in the study region. For Minnesota, the 

Baseline scenario was based on current Minnesota utility plans to meet the Minnesota Renewable 

Energy Standard (RES) and the Solar Energy Standard (SES) with renewable energy (wind, solar,

small hydro, biomass, etc) from the Minnesota-centric area and incorporates refinements from the 

technical study team. For non-Minnesota MISO states in the study footprint, the Baseline scenario 

was based on the prior approved 2013 MISO Transmission Expansion Plan (MTEP13). 

Scenario 1 builds on the Baseline scenario by adding incremental wind and solar (variable 

renewables) generation to the Baseline model to supply a total of 40% of Minnesota annual electric 

retail sales from renewables in the study year and with all states at full implementation of their 

current RESs.

Scenario 2 builds on Scenario 1 by adding incremental wind and solar generation to the Scenario 1 

model to supply 50% of Minnesota electric retail sales from total renewables and by further adding 

incremental wind and solar generation to supply an additional 10% of the non-Minnesota MISO 

North / Central retail electric sales from total renewables (i.e. to increase the MISO footprint 

renewables 10% above full implementation of the current RESs).

Table 1-1 Study Scenarios

Scenario Minnesota RE 

Penetration

MISO Wind & Solar Penetration 

(including Minnesota)

Baseline 28.5% 14.0%

Scenario 1 40.0% 15.0%

Scenario 2 50.0% 25.0%

Note: MISO has an additional 3% renewable energy penetration in all scenarios from 

existing small biomass and small hydro.

The horizon year for this study was 2028 (to represent 2030 conditions). System load levels for 

Minnesota and MISO regions were scaled up from present levels by an assumed annual growth rate 

of 0.5% for Minnesota and 0.75% for the rest of MISO North / Central.

All scenarios, including the Baseline, required more wind and solar generation than what is already 

installed on the grid. Therefore, the study team used a combination of wind/solar resource maps 

and wind/solar profile data (from NREL) to guide selection of sites for prospective future wind and 

solar plants with cumulative capacities consistent with the renewable energy targets for each study 

scenario. Wind Plant sites were distributed among several of MISO’s renewable energy zones
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EXECUTIVE SUMMARY 1-4

(originally developed in the MISO Regional Generation Outlet Study and used in the Multi-Value 

Project Portfolio study).

1.4 Development of Transmission Conceptual Plans

A conceptual transmission plan was developed for each of the study scenarios. System reliability 

was determined through traditional transmission planning methods, criteria, and assumptions. 

Steady state performance characteristics were evaluated with the system intact as well as under 

powerflow contingency conditions (N-1 outages and selected multiple contingency outages per 

NERC TPL Category C2 & C5).

The Baseline scenario started with a transmission model that was consistent with the 2013 MTEP

2023 model. This Baseline transmission model incorporates planned transmission lines, including 

the CapX2020 Group I lines and the MISO Multi-Value Project (MVP) portfolio. A very limited number 

of facilities were overloaded in the Baseline Scenario.

For Scenario 1, a total of 54 transmission mitigations were added to accommodate the increased 

wind and solar generation. These mitigations included transmission line upgrades, transformer 

additions/replacements, and changes to substation terminal equipment, with a total estimated cost 

of $373M. No new transmission lines were required.

In Scenario 2, a total of 17,245 MW of new wind/solar generation was added to increase Minnesota 

renewable energy penetration to 50% and MISO renewable energy penetration to 25%. A total of 9 

new transmission lines and 30 transmission upgrades were added to the Scenario 1 transmission 

system, with a total estimate cost of an additional $2.6B. Note that an undetermined portion of the 

Scenario 2 transmission expansions and upgrades are associated with increasing MISO’s renewable 

penetration from 15% to 25%. 

Note that for the development of transmission conceptual plans, the new wind and solar resources 

were connected to high voltage transmission buses. The actual connection processes will likely 

require additional plant-specific interconnection facilities for the new wind and solar plants.

1.5 Evaluation of Operational Performance

Operational performance of the electric power grid with increased levels of renewable generation 

was analyzed using production simulation analysis, which simulates hourly operation of the system 

for an entire year. The PLEXOS simulation tool uses a Day-Ahead Security Constrained Unit 

Commitment (SCUC) and Real-Time Security Constrained Economic Dispatch (SCED) interleaved 

market dispatch solution. This type of modeling accurately captures the forecast uncertainties 

realized between a Day-Ahead and Real-Time markets. Modeling of forecast uncertainty becomes 

increasingly important when dealing with high levels of wind and solar generation because the 

output tends to be more stochastic in nature.

MISO used the 2013 MTEP Business as Usual (BAU) dataset as a starting point for the Baseline 

Scenario, with modifications to the system load level to reflect the 2028 horizon year for this study. 

The BAU future is considered the status quo future and continues current economic trends. The 

MTEP futures are created by MISO and vetted by the MISO Planning Advisory Committee (PAC) 

stakeholder committee. Information for the production modeling dataset is sourced from Ventyx 
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EXECUTIVE SUMMARY 1-5

and updated through an extensive MISO process to bring it into line with the most current data and 

expected future conditions. Coal unit retirements totaling 12.6 GW were included in the model per 

MISO’s anticipated effects of prior EPA regulations. 

Future EPA regulations, such as the recently proposed Clean Power Plan (111d) which is still in 

development, are not modeled nor considered in this study. The model footprint includes all areas in 

the Eastern Interconnect, with the exception of Florida, ISO New England and Eastern Canada.

For the Scenarios 1 and 2, new wind and solar generation was added at the locations determined in 

the siting task and transmission system upgrades/expansions were added per the conceptual 

transmission plans.

One aspect of the BAU set of assumptions is that many coal plants within MISO will continue to 

operate as they do now. That is, the plants remain on-line when economic market signals would 

have initiated a brief period of decommitment and effectively act as “must-run” units. In order to 

examine the sensitivity to changing this assumption, and to the assumption of coal unit retirements, 

Scenarios 1a and 2a were added to the production simulation analysis as sensitivity cases relative 

to Scenarios 1 and 2. Scenarios 1a and 2a included the following changes in assumptions:

 All coal units were economically committed

 Nine additional coal units in the Minnesota-centric region were assumed to be available (These 

units were assumed unavailable in Scenarios 1 and 2)

 Forced outage modeling of conventional generation was included

The production simulation results were analyzed to assess system operational performance with 

respect to the following parameters; annual energy production by type of generating resource, 

renewable energy resource utilization and curtailment, cycling duty of thermal plants, adequacy of 

ramping capability of the MISO generation fleet, and risk of reserve violations and unserved load. 

For Scenario 1, the results were also screened to select challenging operating conditions for 

dynamic performance, and these operating points were subsequently analyzed with fault 

simulations in the dynamics task.

1.6 Dynamic Performance Analysis

A dynamic simulation model was developed to perform transient stability analysis of the study 

scenarios. A series of dynamic data files were provided by the Minnesota utilities, based on the 

MTEP 2013 dataset. As with the power flow and production system models, new wind and solar 

generation was added at the locations determined in the siting task and transmission system 

upgrades/expansions were added per the conceptual transmission plans. In order to capture 

possible fault-induced delayed recovery issues caused by reduced levels of synchronous 

generation, the load models in the Minnesota-Centric region were refined to include a more detailed 

representation of load composition, including dynamic characteristics. 

New utility-scale wind and solar photovoltaic (PV) plant models were consistent with current NERC 

and FERC minimum requirements (e.g. voltage regulation, power factor, voltage ride-through). Full 

commercial technical capability (e.g. synthetic inertia, frequency response) was not modeled. 

Distributed PV was modeled as lumped generation at locations (per the siting task) with no reactive 

power or voltage regulation capability.
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EXECUTIVE SUMMARY 1-6

New wind plants were split roughly 50/50 between Type 3 (double fed asynchronous generator 

(DFAG) and Type 4 (full converter). 

A representative number of regional power system fault conditions were simulated to stress the 

system in different ways. 

 Faults known to be severe challenges to system transient stability from numerous past stability 

studies,

 Faults in regions with high concentrations of wind and solar plants, where voltage recovery is 

highly dependent on the reactive power support from wind and solar plants.

 Faults affecting major transmission interfaces during periods of high power transfer

The results of all dynamic simulation cases were screened with respect to a set of performance 

criteria, including angular stability, oscillatory stability, voltage dips, and voltage recovery.

Weak system issues were also investigated using the dynamic system models. When the ac system 

impedance is high relative to the aggregate rating of wind and solar generation in a given region, 

the internal controllers and regulators within wind and solar inverters become less stable. If the 

system is excessively weak, control instabilities may occur. Composite short-circuit ratio analysis 

was conducted to determine system strength in the study scenarios with respect to emerging 

industry understanding of this issue.

1.7 Key Findings

This study examined two levels of increased wind and solar generation for Minnesota; 40% 

(represented by Scenarios 1 and 1a) and 50% (represented by Scenarios 2 and 2a). In the 40% 

Minnesota Scenario, MISO North/Central is at 15% (current state RESs). The 50% Minnesota 

Scenario also included an increase of 10% (to 25%) in the MISO North/Central region. Production 

simulation was used to examine annual hourly operation of the MISO North/Central system for all

four of these scenarios. Transient and dynamic stability analysis was conducted for Scenarios 1 

and 1a but not on Scenarios 2 and 2a.

1.7.1 General Conclusions for 40% RE Penetration in Minnesota

With wind and solar resources increased to achieve 40% renewable energy for Minnesota and 15% 

renewable energy for MISO North/Central, production simulation and transient/dynamic stability 

analysis results indicate that the system can be successfully operated for all hours of the year with 

no unserved load, no reserve violations, and minimal curtailment of renewable energy. This 

assumes sufficient transmission mitigations, as described in Section 1.4, to accommodate the 

additional wind and solar resources.

This is operationally achievable with most coal plants operated as baseload must-run units, similar 

to existing operating practice. It is also achievable if all coal plants are economically committed per 

MISO market signals, but additional analysis would be required to better understand implications, 

tradeoffs, and mitigations related to increased cycling duty.
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EXECUTIVE SUMMARY 1-7

Dynamic simulation results indicate that there are no fundamental system-wide dynamic stability 

or voltage regulation issues introduced by the renewable generation assumed in Scenario 1 and 1a. 

This assumes:

 New wind turbine generators are a mixture of Type 3 and Type 4 turbines with standard controls

 The new wind and utility-scale solar generation is compliant with present minimum 

performance requirements (i.e. they provide voltage regulation/reactive support and have zerovoltage ride through capability)

 Local-area issues are addressed through normal generator interconnection requirements

1.7.2 General Conclusions for 50% RE Penetration in Minnesota

With wind and solar resources increased to achieve 50% renewable energy in Minnesota and 25% 

renewable energy in MISO, production simulation results indicate that the system can be 

successfully operated for all hours of the year with no unserved load, no reserve violations, and 

minimal curtailment of renewable energy. This assumes sufficient transmission upgrades, 

expansions and mitigations to accommodate the additional wind and solar resources.

This is operationally achievable with most coal plants operated as baseload must-run units, similar 

to existing operating practice. It is also achievable if all coal plants are economically committed per 

MISO market signals, but additional analysis would be required to better understand implications, 

tradeoffs, and mitigations related to increased cycling duty.

No dynamic analysis was performed for the study scenarios with 50% renewable energy for

Minnesota (Scenarios 2 and 2a) due to study schedule limitations and this analysis is necessary to 

ensure system reliability.

1.7.3 Annual Energy in the Minnesota-Centric Region

Figure 1-1 shows the annual load and generation energy by type for the Minnesota-Centric region. 

Comparing Scenarios 1 and 1a (40% MN renewables) with the Baseline,

 Wind and solar energy increases by 8.5 TWh, all of which contributes to bringing the State of

Minnesota from 28.5% RE penetration to 40% RE penetration

 There is very little change in energy from conventional generation resources

 Most of the increase in wind and solar energy is balanced by a decrease in imports. The 

Minnesota-Centric region goes from a net importer to a net exporter.

Comparing Scenarios 2 and 2a (50% MN renewables) with Scenarios 1 and 1a (40% MN 

renewables),

 Wind and solar energy increases by 20 TWh. Of this total, 4.8 TWh brings the State of Minnesota 

from 40% to 50% RE penetration and the remainder contributes to bringing MISO from 15% to 

25% RE penetration

 Most of the increase in wind and solar energy in the Minnesota-Centric region is balanced by a 

decrease in coal generation and an increase in net exports to neighboring regions

 Gas-fired, combined-cycle generation declines from 5.0 TWh in Scenario 1 to 3.0 TWh in 

Scenario 2.
GE Energy Consulting MRITS Final Report

EXECUTIVE SUMMARY 1-8

Figure 1-1 Annual Energy by Type in Minnesota-Centric Region for Study Scenarios

1.7.4 Cycling of Thermal Plants

Most coal plants were originally designed for baseload operation; that is, they were intended to 

operate continuously with only a few start/stop cycles in a year (mostly due to scheduled or forced 

outages). Increased cycling duty could increase wear and tear on these units, with corresponding 

increases in maintenance requirements. Many coal plants in MISO presently are designated by the 

plant’s owner to operate as “must-run” in order to avoid start/stop cycles that would occur if they 

were economically committed by the market.

Scenarios S1a and S2a assumed that all coal plants in MISO are subject to economic 

commitment/dispatch (i.e., not must-run) based on day-ahead forecasts of load, wind and solar 

energy within MISO. Production simulation results show significant coal plant cycling due to 

economic market signals:

 Small coal units (below 300 MW rating) could have an additional 100 to 200 starts per year, 

beyond those due to forced or planned outages.

 Large coal units (above 300 MW) could have an additional 20 to 100 starts per year
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EXECUTIVE SUMMARY 1-9

Scenarios S1 and S2 assumed almost all coal plants would continue to operate as they do today. 

Coal units were on-line all year (except for scheduled maintenance periods) and were not 

decommitted during periods of low market prices. The results of these scenarios confirmed that the 

coal units could remain must-run with minor impacts on overall operation of the Minnesota-Centric 

region. Coal plant owners could choose to continue the must-run practice to avoid the detrimental 

impacts of increased cycling as wind and solar penetration increases. Doing so would likely incur 

some additional operational costs when energy prices fall below a plant’s breakeven point. Wind 

curtailment would also be about 0.5% higher than if the coal plants were economically committed.

An attractive solution to the coal plant cycling issue may exist between the two bookend cases 

analyzed in this study. Scenarios 1a and 2a assumed that unit commitment was determined on a 

day-ahead basis, using day-ahead forecasts of wind and solar energy. The result was a high 

number of start/stop cycles of coal plants, sometimes with down-times of less than 2 days. If the 

unit commitment process was modified to use a longer term forward market (say 3 to 5 days 

ahead), then coal plant owners could adjust their operational strategy to consider decommitting 

units when prolonged periods of high wind/solar generation and low system loads are forecasted. 

A forward market would depend on longer term forecasts of wind, solar and load energy, consistent 

with the look-ahead period of the market. Although such forecasts would be somewhat less 

accurate than day-ahead forecasts, the quality of the forecasts would likely be adequate to support 

such unit commitment decisions.

This study did not examine the economic or wear-and-tear impacts of increased cycling on coal 

units. Further information on this topic can be found in the NREL Western Wind and Solar 

Integration Study Phase 2 report7 and the PJM Renewable Integration Study report8. 

Combined-cycle (CC) units are better able to accommodate cycling duties than coal plants. 

Simulation results show that combined cycle units in the Minnesota-Centric region experience from 

50 to 200 start/stop cycles per year. Cycling of CC units declines slightly as wind and solar 

penetration increases. This decline is primarily due to a decrease in CC plant utilization as wind and 

solar energy increases.

1.7.5 Curtailment of Wind and Solar Energy

In general, a small amount of curtailment is to be expected in any system with a significant level of 

wind and solar generation. There are some operating conditions where it is economically efficient 

to accept a small amount of curtailment (i.e., mitigation of that curtailment would be 

disproportionately expensive and not justifiable).

Overall curtailment in the Minnesota-Centric region is relatively small in all study scenarios, as 

shown in Table 1-2. Wind curtailment in Baseline and Scenario 1 is primarily due to local

transmission congestion at a few wind plants. This congestion could be mitigated by transmission 

modifications, if economically justifiable. 

Wind curtailment in Scenario 2 is due to system-wide operational limits during nighttime hours, 

when many baseload generators are dispatched to their minimum output levels. This type of 

curtailment could be reduced by decommitting some baseload generation via economic market 

 

7

http://www.nrel.gov/electricity/transmission/western_wind.html

8

http://www.pjm.com/committees-and-groups/task-forces/irtf/pris.aspx
GE Energy Consulting MRITS Final Report

EXECUTIVE SUMMARY 1-10

signals. The effectiveness of this mitigation option is illustrated by comparing Scenario 2 (coal units 

must-run) with Scenario 2a (economic coal commitment). Wind curtailment decreases from 2.14% 

to 1.60% (reduction of 332 GWh of wind curtailment). Solar curtailment decreases from 0.42% to 

0.24% (reduction of 12 GWh of solar curtailment).

Table 1-2 Wind and Solar Curtailment for Study Scenarios

Scenario Baseline Scenario 1 Scenario 1a Scenario 2 Scenario 2a

Wind Curtailment 0.42% 1.00% 1.59% 2.14% 1.60%

Solar Curtailment 0.09% 0.00% 0.23% 0.42% 0.24%

Note: Curtailment is calculated as a percentage of available annual wind or solar energy.

1.7.6 Other Operational Issues

No significant transmission system congestion was observed in any of the study scenarios with the 

assumed transmission upgrades and expansions. Transmission contingency conditions were 

considered in both the powerflow analysis used to develop the conceptual transmission system and 

the security-constrained economic dispatch in the production simulation analysis.

Ramp-range-up and ramp-rate-up capability of the MISO conventional generation fleet increases 

with increased penetration of wind and solar generation. Conventional generation is generally 

dispatched down rather than decommitted when wind and solar energy is available, which gives 

those generators more headroom for ramping up if needed.

Ramp-range-down and ramp-rate-down capability of the MISO conventional generation fleet 

decreases with increased penetration of wind and solar generation. In Scenario 2, there are 500 

hours when ramp-rate-down capability of the conventional generation fleet falls below 100 

MW/min. Periods of low ramp-down capability coincide with periods of high wind and solar 

generation. Wind and solar generators are capable of providing ramp-down capability during these 

periods. MISO’s existing Dispatchable Intermittent Resource (DIR) process already enables this for

wind generators. It is anticipated that MISO would expand the DIR program to include solar plants 

in the future.

1.7.7 System Stability, Voltage Support, Dynamic Reactive Reserves

No angular stability, oscillatory stability or wide-spread voltage recovery issues were observed over 

the range of tested study conditions. The 16 dynamic disturbances used in stability simulations 

included key traditional faults/outages as well as faults/outages in areas with high concentrations 

of renewables and high inter-area transmission flows. System operating conditions included light 

load, shoulder load and peak load cases, each with the highest percent renewable generation

periods in the Minnesota-Centric region.

Overall dynamic reactive reserves are sufficient and all disturbances examined for Scenarios 1 and 

1a show acceptable voltage recovery. The South & Central and Northern Minnesota regions get the 

majority of their dynamic reactive support from synchronous generation. Maintaining sufficient 

dynamic reserves in these regions is critical, both for local and system-wide stability. 
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EXECUTIVE SUMMARY 1-11

Southwest Minnesota, South Dakota and at times Iowa get a significant portion of dynamic reactive 

support from wind and solar resources. Wind and Solar resources contribute significantly to 

voltage support/dynamic reactive reserves. The fast response of wind/solar inverters helps voltage 

recovery following transmission system faults. However, these are current-source devices with little 

or no overload capability. Their reactive output decreases when they reach a limit (low voltage and 

high current). 

Synchronous machines (either generators or synchronous condensers), on the other hand, are 

voltage-source devices with high overload capability. This characteristic will strengthen the system 

voltage, allowing better utilization of the dynamic capability of renewable generation. The 

mitigation methods discussed below, namely stiffening the ac system through new transmission or 

synchronous machines, will also address this concern.

Local load areas, such as the Silver Bay and Taconite Harbor area, require reactive support from 

synchronous machines due to the high level of heavy industrial loads. If all existing synchronous 

generation in this region is off line (i.e. due to retirement or decommitment), reinforcements such as 

new transmission or synchronous condensers would be required to support the load.

Dynamic simulation results indicate that it is critical to maintain sufficient system strength and 

dynamic reserves to support high flows on the Northern Minnesota 500 kV lines and Manitoba highvoltage direct-current (HVDC) lines. Insufficient system strength and reactive support will limit 

Manitoba exports to the U.S. Existing transmission expansion plans, as modeled in this analysis,

address these issues and are sufficient for the anticipated levels of Manitoba exports.

The Manitoba HVDC ties and the 500 kV transmission system in Northern Minnesota require 

reactive support from synchronous generators, the Dorsey and Riel synchronous condensers, and 

the Forbes static var compensator (SVC) to maintain the expected level of Manitoba exports. 

Without sufficient reactive reserves, the system could be unstable for nearby transmission 

disturbances. The current transmission plans, as modeled in this analysis, address this issue. 

1.7.8 Weak System Issues

Composite Short-Circuit Ratio (CSCR) is an indicator of the ability of an ac transmission system to

support stable operation of inverter-based generation. A system with a higher CSCR is considered 

strong and a system with a lower CSCR is considered to be weak. CSCR is calculated as the ratio of 

the composite short-circuit MVA at the points of interconnection (POI) of all wind/solar plants in a 

given area to the combined MW rating of all those wind and solar generation resources.

Low CSCR operating conditions can lead to control instabilities in inverter-based equipment (Wind, 

Solar PV, HVDC and SVC). Instabilities of this nature will generally manifest as growing 

voltage/current oscillations at the most affected wind or solar plants. In the worst conditions (i.e., 

very low CSCR), oscillations could become more wide-spread and eventually lead to loss of 

generation and/or damage to renewable generation equipment if not adequately protected against 

such events.

This is a relatively new area off concern within the industry. The issue has emerged as the 

penetration of wind generation has grown. Understanding of the fundamental stability issues is 

rapidly growing as more wind plants are being installed in regions with weak ac systems. 
GE Energy Consulting MRITS Final Report

EXECUTIVE SUMMARY 1-12

Equipment vendors, transmission planners and consultants are all working to gain a better 

understanding of the issues. Modeling and simulation tools have already been developed to enable 

detailed analysis of the phenomena. Wind and solar inverter control systems are being modified to 

improve weak system performance.

Synchronous machines (either generators or synchronous condensers) contribute short-circuit 

strength to the transmission system and therefore increase CSCR. Therefore, system operating 

conditions with more synchronous generators online will have higher CSCR. Also, stronger 

transmission ties (additional transmission lines or transformers, or lower impedance transformers) 

between synchronous generation and regions of wind and solar generation will increase CSCR. 

SVCs and STATCOMs do not contribute short-circuit current, and because they are electronic

converter based devices with internal control systems similar to wind/solar inverters, their presence 

in a weak system region could further reduce the effective CSCR and exacerbate the control system 

stability issues that occur in weak system conditions.

There are two general situations where weak system issues generally need to be assessed:

 Local pockets of a few wind and solar plants in regions with limited transmission and no nearby 

synchronous generation (e.g. plants in North Dakota fed from Pillsbury 230 kV near Fargo).

 Larger areas such as Southwest Minnesota (Buffalo Ridge area) with a very high concentration 

of wind and solar plants and no nearby synchronous generation

This study examined the sensitivity of weak system issues in Southwest Minnesota. Observations 

are as follows:

The trouble spots identified in this analysis are not very sensitive to existing synchronous generation 

commitment. While there is very little synchronous generation within the area, the region is 

supported by a strong networked 345 kV transmission grid. Primary short circuit strength is from a 

wide range of base-load units in neighboring areas, and interconnected via the 345 kV transmission 

network. Commitment, decommittment or outages of individual synchronous generators do not 

have significant impact on CSCR in these identified areas.

Transmission outages will lower system strength and make the issue worse. When performing 

CSCR and weak system assessments as wind and solar penetration increases, it will be prudent to 

consider normal and design-criteria outages at a minimum (i.e, outage conditions consistent with 

MISO reliability assessment practices).

1.7.9 Mitigations

There are two approaches to improving wind/solar inverter control stability in weak system 

conditions:

 To improve the inverter controls, either by carefully tuning the equipment control functions or 

modifying the control functions to be more compatible with weak system conditions. With this 

approach, wind/solar plants can tolerate lower CSCR conditions.

 To strengthen the ac system, resulting in increased short-circuit MVA at the locations of the 

wind/solar plants. This approach increases CSCR.
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EXECUTIVE SUMMARY 1-13

The approaches are complementary, so the ultimate solution for a particular region would likely be 

a combination of both.

Mitigation through Wind/PV Inverter Controls

Standard inverter controls and setting procedures may not be sufficient for weak system 

applications. Loop gains of internal control functions inherently increase when system impedance 

increases, thereby reducing the stability margin of the controllers. Developers and equipment 

vendors must be made aware when new plants are being proposed for weak system regions so 

they can design/tune controls to address the issue. Wind plant vendors have made significant 

progress in designing wind and solar plant control systems that are compatible with weak system 

applications.

This approach becomes somewhat more difficult when there are wind/solar plants from multiple 

vendors in one region. The level of analysis requires detailed modeling of all affected wind plants at 

a level of detail that requires the use of proprietary control design information from the vendors. 

Vendors are very reluctant to share such data, except with independent consultants who can 

guarantee strict data security. However, this approach is gaining traction and a few projects have 

made effective implementations. The key to success is that project developers and equipment 

vendors must be informed beforehand that a given wind or solar plant will be installed at a weak 

system location. This enables the appropriate control design studies to be initiated before the 

project is installed.

In the event that such control-based approaches are not sufficient, it would be possible to further 

improve weak system performance by employing one or more of the system-level mitigations 

discussed below.

Mitigation by Strengthening the AC System

CSCR analysis of the Southwest Minnesota region shows that synchronous condensers located near 

the wind and solar plants would be a very effective mitigation for weak system issues. Synchronous 

condensers are synchronous machines that have the same voltage control and dynamic reactive 

power capabilities as synchronous generators. Synchronous condensers are not connected to

prime movers (e.g. steam turbines or combustion turbines), so they do not generate power.

Other approaches that reduce ac system impedance could also offer some benefit:

 Additional transmission lines between the wind/solar plants and synchronous generation plants

 Lower impedance transformers, including wind/solar plant interconnection transformers

Series capacitors on transmission lines could be used to increase CSCR and to improve the 

transmission system’s capability to transfer energy out of regions with high concentrations of wind 

and solar resources. However, series capacitors create subsynchronous frequency resonances in 

the transmission system which affect the performance of control systems within wind and solar 

plants. These resonances introduce an additional challenge to wind/solar plant control designs, 

which must maintain stable operation in the presence of the resonant conditions.Mitigation through 
GE Energy Consulting MRITS Final Report

EXECUTIVE SUMMARY 1-14

“must-run” operating rules for existing generation was found to be not very effective. The plants 

with synchronous generators are not located close enough to effected wind/solar plants.
GE Energy Consulting MRITS Final Report

PROJECT OVERVIEW 2-1

2 PROJECT OVERVIEW

2.1 Background

In 2013 the Minnesota Legislature adopted a requirement for a Renewable Energy Integration and 

Transmission Study1 (MRITS). The MN utilities and transmission companies, in coordination with 

MISO, conducted the engineering study. The Department of Commerce directed the study and 

appointed and led the Technical Review Committee (TRC). It is an engineering study of increasing 

the Minnesota Renewable Energy Standard to 40% by 2030, and to higher proportions thereafter, 

while maintaining system reliability. 

The final study includes: 

1. A conceptual plan for transmission for generation interconnection and delivery and for 

access to regional geographic diversity and regional supply and system flexibility, and 

2. Identification and development of potential solutions to any critical issues encountered. 

All utilities with Minnesota retail electric sales and all Minnesota transmission companies 

participated and/or were represented in the study. Eight Minnesota Local Balancing Authorities are 

represented and over 85% of the Minnesota retail sales are in the four largest Local Balancing 

Authorities: Xcel Energy (NSP), Great River Energy, Minnesota Power, and Otter Tail Power. The study 

area is within the NERC reliability region Midwest Reliability Organization (MRO). Nearly all of the 

Minnesota retail sales are within the Midcontinent Independent System Operator (MISO). The Local 

Balancing Authorities within MISO, including the Minnesota LBAs, are functionally consolidated.

Prior studies of relevance include the 2006 Minnesota Wind Integration Study2, the 2007 Minnesota 

Transmission for Renewable Energy Standard Study3, the 2009 Minnesota RES Update, Corridor, and 

Capacity Validation Studies, the 2008 and 2009 Statewide Studies of Dispersed Renewable 

Generation4, the 2010 Regional Generation Outlet Study, the 2011 Multi Value Project Portfolio 

Study, the 2013 Minnesota Biennial Transmission Project Report5, the 2013 MISO Transmission 

Expansion Plan, and recent and ongoing MISO transmission expansion planning work6 .

2.2 Objectives

1. Evaluate the impacts on reliability and costs associated with increasing Renewable Energy 

to 40% of Minnesota retail electric energy sales by 2030, and to higher proportions 

thereafter;

 

1 MN Laws 2013, Chapter 85 HF 729, Article 12, Section 4; MPUC Docket No. CI-13-486.

2

2006 MN Wind Integration Study. Prepared for the MPUC, Nov 2006. Final Report Volumes I & II, Final Report 

Presentation. http://www.puc.state.mn.us/PUC/electricity/013752 

3

“Minnesota RES Update Study Technical Report.” March 2009. “RES Transmission Report.” November 2007.

“Southwest Twin Cities – Granite Falls Transmission Upgrade Study Technical Report.” March 2009.

“Capacity Validation Study Report.” March 2009. http://www.minnelectrans.com/reports.html

4 Dispersed Renewable Generation Studies. June 2008 and September 2009. 

http://mn.gov/commerce/energy/topics/resources/Reports-Data/Energy-Reports.jsp

5

http://www.minnelectrans.com/, November 1, 2013.

6

https://www.misoenergy.org/Planning/TransmissionExpansionPlanning/Pages/TransmissionExpansionPlanning.aspx
GE Energy Consulting MRITS Final Report

PROJECT OVERVIEW 2-2

2. Develop a conceptual plan for transmission necessary for access to regional geographic 

diversity and regional system flexibility;

3. Identify and develop options to manage the impacts of the renewable energy resources;

4. Build upon prior wind integration studies and related technical work; Coordinate with 

recent and current regional power system study work;

5. Produce meaningful, broadly supported results through a technically rigorous, inclusive 

study process.

2.3 Study Timeline

June – August 2013

Commerce: Reviewed prior and current studies and worked with stakeholders and study participants to

identify key issues, began development of a draft technical study scope, and accepted 

recommendations of qualified Technical Review Committee (TRC) members;

September 2013

Commerce: Held a stakeholder meeting to discuss the objectives, scope, schedule, and process; 

Commerce appointed the Technical Review Committee; 

September / October 2013

Commerce, in consultation with the MN utilities, finalized the study scope; 

October 2013

The MN utilities, in consultation with Commerce, identified the technical study team; 

November 2013 – October 2014

The study was completed. The Technical Review Committee has reviewed all technical work in this study 

on an ongoing basis, throughout the study.

2.4 Study Scope

This study is focused on the reliability impacts of increased levels of variable renewables (wind and 

solar generation) and the associated costs of those impacts.

MRITS builds upon prior wind integration studies and related technical work and is coordinated with 

recent and current regional power system study work. The study scope was developed from 

statutory guidance, stakeholder input, and technical study team refinement. 

MRITS incorporates three core and interrelated analyses: 1) Power flow analysis for development of 

a conceptual transmission plan, which includes transmission necessary for generation 

interconnection and delivery and for access to regional geographic diversity and regional supply 

and demand side flexibility; 2) Production simulation analysis for evaluation of operational 

performance, including reserve violations, unserved load, wind / solar curtailments, thermal cycling, 

and ramp rate and ramp range, and, to screen for challenging time periods; and 3) Dynamics 

analysis, which includes transient stability analysis and weak system strength analysis. 
GE Energy Consulting MRITS Final Report

PROJECT OVERVIEW 2-3

The MRITS study area is Minnesota-centric, which focuses on the combined operating areas of the 

Minnesota utilities and transmission companies, in the context of the MISO North/Central areas and 

the neighboring regions to the west and north. 

The base study models (baseline and scenarios) are coordinated with and consistent with MISO 

models and databases including dispatch to the MISO market. Additional options were considered 

in Task 7 (Identify & Develop Mitigations / Solutions) as needed.

The key study tasks are:

 Develop Study Scenarios; Site Wind and Solar Generation (Task 1)

 Perform Production Simulation Analysis (Tasks 2 and 4)

 Perform Power Flow Analysis; Develop Transmission Conceptual Plan (Task 3)

 Evaluate Operational Performance (Task 6a)

 Screen for Challenging Periods; Perform Dynamics Analysis (Task 5 and 6b)

 Identify and Develop Mitigations and Solutions (Task 7) 

The study task flow chart is shown in Figure 2-1.
GE Energy Consulting MRITS Final Report

PROJECT OVERVIEW 2-4

Figure 2-1 Flowchart of Project Tasks
GE Energy Consulting MRITS Final Report

PROJECT OVERVIEW 2-5

2.5 Study Scenarios

The MRITS study scenarios were developed from statutory guidance, stakeholder input, and 

technical study team refinement. 

The study year of 2028 was selected to help ensure that all models and system data were 

coordinated with and are consistent with MISO MTEP13 models and databases. It was also thought 

that 2028 was suitably near to 2030 as written in legislation, especially considering the difficulty in 

projecting an accurate load forecast fifteen years into the future.

Each of the study scenarios builds on the prior scenario, starting with the Baseline. The Baseline 

scenario has sufficient renewable energy generation to satisfy the current renewable energy 

standards and solar energy standards for all states in the study region. For Minnesota, the Baseline 

scenario was based on current Minnesota utility plans to meet the Minnesota Renewable Energy 

Standard (RES) and the Solar Energy Standard (SES) with renewable energy (wind, solar, small hydro, 

biomass, etc.) from the Minnesota-centric area and incorporates refinements from the technical 

study team. For non-Minnesota MISO states in the study footprint, the Baseline scenario was based 

on the prior approved 2013 MISO Transmission Expansion Plan (MTEP13). 

1. Scenario 1 builds on the Baseline scenario by adding incremental wind and solar (variable 

renewables) generation to the Baseline model to supply a total of 40% of Minnesota 

annual electric retail sales from renewables in the study year with all states at full 

implementation of their current RESs.

2. Scenario 2 builds on Scenario 1 by adding incremental wind and solar generation to the 

Scenario 1 model to supply 50% of Minnesota electric retail sales from total renewables 

and by further adding incremental wind and solar generation to supply an additional 10% 

of the non-Minnesota MISO North / Central retail electric sales from total renewables (i.e. to 

increase the MISO footprint renewables 10% above full implementation the current RESs).

Model Minnesota MISO North/Central (includes MN)

Baseline 28.5% 14.0%

Scenario 1 40.0% 15.0%

Scenario 2 50.0% 25.0%

Within each of the scenarios, the allocation of the RES was further divided between wind and solar 

resources and within the solar allocation was divided between centralized utility sized solar (UPV) 

and distributed small PV (DPV).

It was assumed that the growth in energy sales for Minnesota and MISO (includes Minnesota) would 

increase by 0.5% and 0.75% respectively. Given these assumptions and the allocation of resources 

for each scenario, Table 2-1 describes the amount of additional wind and solar resources included 

in the models.
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PROJECT OVERVIEW 2-6

Table 2-1 Wind and Solar Resource Allocations for Study Scenarios

2013 2028

MN Retail Sales (GWH) 66,093 71,227

Wind MW PV MWac

Minnesota-centric Wind (MW) Total Incremental Total Incremental

Existing + signed GIA 8,922 UPV DPV

Baseline 5,990 457 361 96

Scenario 1 7,521 1,931 1,371 723 191

Scenario 2 8,131 610 4,557 2,756 430

2013 2028

MISO Retail Sales (GWH) 498,000 557,000

Wind MW PV MWac

MISO (includes Minnesota) Wind (MW) Total Incremental Total Incremental

Existing + signed GIA 15,320 UPV DPV

Baseline 22,229 6,900 1509 1,413 96

Scenario 1 24,160 1,931 2,442 723 210

Scenario 2 37,796 13,636 6,201 5,636 565

Note that Minnesota Baseline renewable percentage includes qualifying small hydro and biomass. 

MISO retail sales and percentages are MISO North and Central (they do not include MISO South).

Minnesota wind generation was sited Minnesota-centric (Minnesota, North Dakota, South Dakota, 

and northern Iowa). Minnesota solar generation was sited in Minnesota, eastern South Dakota and 

northern Iowa. MISO wind and solar generation was sited per the MISO Transmission Expansion 

Planning assumptions. The generation siting process and assumptions are described in greater 

detail in subsequent sections of this report.
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-1

3 WIND AND SOLAR GENERATION SITING

Per the project plan, this task focused on selecting sites for wind and solar resources to meet the 

requirements of the study scenarios. Minnesota wind and solar resources were sited in the 

Minnesota-centric area (MN, ND, SD, northern Iowa) based on existing wind and solar, planned wind 

and solar (including those with signed Interconnection Agreements, wind sites in MVP portfolio 

planning), and MN utility announced projects. Wind and solar resources in the interconnection 

queues also helped inform the siting selection process.

MISO future wind and solar was sited per MTEP guidelines (e.g. at expanded RGOS zones on a pro 

rata basis).

As described in the previous chapter, there are significant amounts of new wind and solar 

generation to locate in Minnesota and within MISO for the study scenarios. Table 3-1 and Table 3-2

show the Minnesota and MISO wind and solar build-outs for the Baseline, Scenario 1 and Scenario 2 

cases to be studied. Table 3-3 shows the key assumptions that were used during the build-out 

process.

Table 3-1 Minnesota-Centric Wind and Solar Amounts to be Sited

Table 3-2 Non-MN-Centric Wind and Solar Amounts to be Sited
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-2

Table 3-3 Key assumptions for Wind & Solar Build-Outs

3.1 Siting for Wind Resources

The wind profile data used in this study were derived from existing wind data sets from NREL. The 

data set are for the years, 2004, 2005 and 2006 and was initially developed for Eastern Wind 

Integration and Transmission Study (EWITS) and updated for Eastern Renewable Generation

Integration Study (ERGIS) on hourly and 10 minutes intervals. MISO had been using the data set 

year 2005 but downloaded and updated their data using the updated ERGIS 2006 data set. 

MISO also added recently signed Generation Interconnection Agreements for Xcel Energy and 

MidAmerican Energy Company (MEC) wind generation projects and these reduced the MN, ND & IA 

future/proxy wind to compensate for the addition. MISO also minimized wind siting at RGOS Zones 

Wind

Annual Ann CF Ann CF

Capacity MWhac/ MWhac/

Factor fraction MWac fraction MWac

Minnesota MN

38% existing

38% 80% 18% 20% 17% Baseline

42% 80% 18% 20% 17% S1

42% 85% 18% 15% 17% S2

MISO MISO

32% existing

37% 90% 17% 10% 16% Baseline

37% 90% 17% 10% 16% S1

37% 90% 17% 10% 16% S2

PV assumptions:

- S1 20% distributed, 80% centralized

- S2 15% distributed, 85% centralized

- MN Centralized: Fixed; module / inverter = 1.25

- MISO Centralized: Fixed&Tracker (1-axis); module / inverter = 1

 DC to AC derate: 0.81

- All Distributed: Fixed; module / inverter = 1

 DC to AC derate: 0.81

12/20/13

Utility

Scale PV

Residential &

Commercial PV

DPV

Distributed

CPV

Central

Annual Capacity 

Factor (AC)

Annual Capacity 

Factor (AC)
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-3

MN-E, MN-H, MN-L, WI-F and allowed non-MN MISO wind, to serve non-Minnesota MISO state RPSs, 

to include MN sited wind generation. The MISO wind was then prorated on the projected 2018, 2023 

and 2028 additions. Bus names and bus numbers were corrected accordingly.

3.1.1 Minnesota Wind

Minnesota Wind is intended to serve the Minnesota RES and is sited in the Minnesota-centric area

which includes all of Minnesota, parts of North Dakota and South Dakota as well as northern Iowa.

A For the Baseline Model

MTEP13 siting principles which uses the current MISO state RPSs, and corresponding wind

siting including the existing and planned wind sites. (Table 3-4)

B For Scenario 1

Adding 1931 MW into the Minnesota-centric area and sited per Minnesota wind resource and 

consistent with expanded MISO renewable energy (MVP/RGOS) zones (see Table 3-5). Xcel 

Energy had recently signed Generation Interconnection Agreements for four wind plants 

totaling 750 MW and this was included in the 1931 MW and these locations are shown in 

green in Figure 3-2.

C For Scenario 2 

Minnesota wind for Scenario 2 was increased by 610 MW above what was in Scenario 1. See

Table 3-6.

3.1.2 MISO (non-MN) Wind

Non-MN Wind is intended to serve the MISO state RPSs for states other than Minnesota. The wind 

resources are sited per MTEP wind resource in the MISO footprint including in the Minnesota-Centric 

Area.

A For Baseline 

Beyond the wind included in the MTEP 2013 models, which includes the existing and planned 

wind projects in MISO, 6900 MW was added MISO wide to meet the current MISO state RPSs 

(including MN). This is shown in Table 3-2.

B For Scenario 1

No non-MN MISO wind was added.

C For Scenario 2

Beyond the Baseline, 13,026 MW of non-Minnesota wind was added baseline in the RGOS 

zones primarily in Iowa, Illinois, Indiana and Michigan (see Table 3-8). MEC had recently signed 

generation interconnection agreements for four wind plants totaling 932.6 MW and this was 

included in the 13,026 MW total. These four locations are shown in green in Figure 3-3.
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-4

Figure 3-1 RGOS Wind Zones
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-5

Table 3-4 MISO Wind Locations-Baseline

2018 2023 2028

IA-B SHELDON 610 23 63 239 934

IA-F SHELDON 675 23 61 233 992

IA-G RAUN 805 21 56 214 1096

IA-H GRIMES 415 17 45 170 647

IA-I GRIMES 383 10 26 101 520

IA-J WEBSTER 1735 1 4 14 1754

IL-F BROKAW 891 126 48 21 1085

IL-K PAWNEE 420 94 71 0 585

IN-E WESTWD 350 11 30 115 507

IN-K HORTVL 200 15 40 154 409

MI-B REESE 305 378 0 0 683

MI-C WYATT 233 345 0 0 579

MI-D WYATT 112 278 0 0 390

MI-E REESE 333 378 0 0 711

MI-F WYATT 32 378 0 0 410

MI-I PALISADES 191 0 0 191

MN-B LYON COUNTY 985 6 16 60 1066

MN-E CHANARAMBIE 891 891

MN-H LAKEFIELD 553 553

MN-K HUNTLEY 1251 14 36 140 1441

MN-L PLEASANT VALLEY 813 813

MO-A ATCHISON T 146 224 0 0 370

MO-C ADAIR 314 0 0 314

MT-A BAKER 200 11 28 107 345

ND-G GRE-MCHENRY 780 16 41 156 994

ND-K ELLENDALE 171 13 34 130 348

ND-M GRE-RAMSEY 887 4 12 48 952

SD-H BIG STONE SOUTH (West of) 23 63 239 324

SD-J BIG STONE SOUTH 40 23 61 232 355

SD-L BROOKINGS 207 23 63 239 531

WI-B DUBUQUE CTY 121 18 49 186 374

WI-D NORTH APPLETON 267 20 54 203 543

WI-F 520.6 0 0 0 521

Totals 15,329 3000 900 3000 22,229

RGOS 

Zone

Bus Name

MISO - Baseline Wind 

Additions (MW)

Existing 

and 

Signed 

GIAs 

(MW)

Total wind amounts 

in Baseline Scenario 

(MW)
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WIND AND SOLAR GENERATION SITING 3-6

Table 3-5 Incremental Minnesota-Centric Wind Locations for Scenarios 1&2

Table 3-6 Minnesota-Centric Wind Siting

IA-B SHELDON 125 50 175

IA-J WEBSTER 75 10 85

MN-B LYON COUNTY 218 191 409

MN-E CHANARAMBIE 50 50

MN-H LAKEFIELD 125 125

MN-K HUNTLEY 150 129 279

MN-L PLEASANT VALLEY 75 75

MN ODELL (G826) 200 200

MN PLEASANT VALLEY (J278) 200 200

ND-G GRE-MCHENRY 0 80 80

ND-K ELLENDALE 50 50

ND-M GRE-RAMSEY 25 30 55

N D BORDERS (J290) 150 150

N D COURTNEY (J262/J263) 200 200

SD-H BIG STONE SOUTH (West of) 50 50

SD-J BIG STONE SOUTH 108 50 158

SD-L BROOKINGS 130 70 200

Totals 1931 610 2541

Incremental MN 

wind for Scenario 2

Total Scenario 1 & 2 

Incremental MN 

wind 

RGOS Zone Bus Name

Incremental MN 

Wind for Scenario 1
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WIND AND SOLAR GENERATION SITING 3-7

Table 3-7 Non Minnesota MISO Wind Locations- Scenario 1 & 2

Incremental NonMN Wind for 

Scenario 1

Incremental NonMN Wind for 

Scenario 2

IA-B SHELDON 361

IA-F SHELDON 397

IA-G RAUN 350

IA-H GRIMES 240

IA-I GRIMES 67

IA-J WEBSTER 25

IA HIGHLAND (R39) 500

IA LUNDGREN (R42) 250

IA VIENNA II (H009) 44

IA WELLSBURG (H021) 138.6

IL-F BROKAW 398

IL-K PAWNEE 345

IN-E WESTWD 329

IN-K HORTVL 425

MI-B REESE 736

MI-C WYATT 676

MI-D WYATT 552

MI-E REESE 736

MI-F WYATT 736

MI-I PALISADES 391

MN-K HUNTLEY 261

MO-A ATCHISON T 453

MO-C ADAIR 620

MT-A BAKER 309

ND-G GRE-MCHENRY 353

ND-K ELLENDALE 367

ND-M GRE-RAMSEY 130

SD-H BIG STONE SOUTH (West of) 638

SD-J BIG STONE SOUTH 571

SD-L BROOKINGS 568

WI-B DUBUQUE CTY 507

WI-D NORTH APPLETON 550

WI-F 0

Totals 0 13,026

RGOS 

Zone

Bus Name
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WIND AND SOLAR GENERATION SITING 3-8

Table 3-8 Non-MN MISO Wind Siting

Figure 3-2 MN & Non MN Scenario 1 Wind Siting
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-9

Figure 3-3 RGOS Wind Zones w/MN & Non MN Scenario 2

3.2 MISO Wind Reassignment

The Non-MN MISO wind was sited per as described in the previous section. However after the 

production simulation analysis showed significant amounts of wind congestion at some plants in 

western MISO, it was decided to relocate some of this congested wind sites to less congested areas. 

A portion of the wind generation was moved from the “Top 4” congested sites and reassigned to the 

“Bottom 10” least congested sites. 

This reassigned generation only involved the non-MN MISO wind and this generally relocated the 

wind generation to the south and east locations with lower capacity factor. As a result of the 

placing this generation at sites with lower capacity factors, or reduced average wind speeds, the 

wind nameplate had to be increased in order to maintain the equivalent wind energy prior to and 

after the shift. 

Table 3-9 displays the shifted sites, nameplate capacity and annual energy outputs. Figure 3-4

shows the locations of the wind sites that were shifted; the sites in red represent the 4 most 

congested sites. The wind resources from these locations were shifted to the sites shown in yellow.
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-10

Table 3-9 Wind Shift from the 4 Most-Congested to the 10 Least-Congested Sites

Figure 3-4 Wind Shift from the 4 Most-Congested to the 10 Least-Congested Sites

Zone Company

Basecase 

(MW)

S1 

(MW)

S2 

(MW)

Basecase 

Curtailment 

(GWh)

S1 

Curtailment 

(GWh)

S2 

Curtailment 

(GWh)

S2 Capacity 

Adjustment (MW)

S2 Energy 

Adjustment 

(GWh)

SD-H:1 OTP 324 374 1,012 25.7 0.9 1,226.6 (311) (1,229)

ND-K:1 MDU 177 227 595 5.0 26.3 895.2 (293) (898)

IA-G:1 MEC 292 292 642 0.6 1.7 495.6 (129) (499)

MN-K:1 Alliant West 190 340 731 3.7 30.9 444.4 (118) (447)

IA-B:1 Alliant West - Interstate Power & Light 984 449 853 - 3.2 340.3 (851) (3,293)

H009:1 MEC - - 44 - - 0.3 8 3 329

H021:1 Alliant West - - 139 - - 0.1 9 7 329

IL-F:1 Ameren IL 194 194 591 - - - 106 329

IN-E:1 Duke Energy IN 157 157 486 - - - 103 329

MI-C:1 Detroit Edison 345 345 1,022 - - - 111 329

MI-B:1 Detroit Edison 378 378 1,114 - - - 8 9 329

MI-F:1 Detroit Edison 378 378 1,114 - - - 9 8 329

MI-E:1 Detroit Edison 378 378 1,114 - - - 8 0 329

MI-I:1 Consumers Energy 191 191 582 - - - 8 4 329

MI-D:1 Detroit Edison 278 278 830 - - - 9 6 329

947 3293

Net 96 0
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-11

3.3 Siting of PV Solar Resources

The Non-Minnesota MISO photovoltaic solar data set came from the ERGIS hourly solar data. For 

Minnesota solar data, NREL developed additional 2006 hourly solar power data with 10 km 

resolution, which allow the siting of additional utility-scale solar in Minnesota that was not present 

in the ERGIS data.

For utility-scale solar plants in Minnesota, the data was processed to create individual solar plants 

simulating a 1.25:1 module-to-inverter ratio. This was done to approximate the additional solar 

panels that are used to reduce the losses and increase the capacity factor of utility-scale solar 

plants by having the capacity of the photovoltaic panels exceed the capacity of the inverter. This 

process involved setting the ac rating at 80% of the dc nameplate rating and clipping the output to 

the ac rating. (For example, the raw values for a 50 MWdc PV plant were limited to 40 MWac to 

create a 40 MW plant for the study.) The capacity values were revised accordingly so they reflect 

the ac bus bar values. 

The ERGIS data already contained values for the utility-scale solar plants outside of Minnesota and 

the distributed solar (both inside and outside of Minnesota). These values reflected typical losses 

due to inverter efficiency and other factors. The distributed solar dc to ac losses varied from 79% to 

85% with an average of 82%. Non-Minnesota utility-scale solar losses varied from 77% to 89% with 

an average of 83%. However the assumed annual energy numbers remain the same because the 

ac ratings are based on the maximum output value for each site rather than the dc values.

3.3.1 Minnesota PV Solar

The solar generation added in the Minnesota-Centric area was split between Distributed PV and 

Centralized utility scale PV on a 20%/80% basis for the Baseline and Scenario 1, and a 15%/85% 

split for Scenario 2, respectively. The 1.5% solar mandate enacted in 2013 legislation dictated that 

at least 10% of the solar was to be distributed, but the splits were determined in the stakeholder 

study scoping process. The distributed PV was assumed to be sited at load centers. 

The Centralized utility scale PV was spread by solar resource largely over the southern half of 

Minnesota, however there was some sited in the northern portion of the state as utilities in the 

northern part of the state indicated that they would prefer to site closer to their service territory 

even knowing that the energy output would be slightly less than the southwest portion of the state. 

Note: there is an approximately 10% decrease in solar resource strength from the south west 

corner of MN to Duluth, MN in the north east. The solar strength does not follow an intuitive rule 

where further south equals stronger solar strength, but rather the solar strength gradient generally 

follows a NW to SE line, such that Alexandria, MN has about the same solar value as the Twin Cities.

This is shown in Figure 3-5.
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-12

Figure 3-5 United States Photovoltaic Solar Resource (portion of)

 For the Baseline scenario, a total of 457 MWac PV was added with 96 MW being distributed and 

361 MW classified and sited as Utility scale solar.

 For Scenario 1, a total of 914 MWac PV was added with 191 MW being distributed and 723 MW 

classified and sited as Utility scale solar.

 For Scenario 2, a total of 3,186 MWac PV was added with 430 MW being distributed and 2,756 

MW classified and sited as Utility scale solar.

These solar generation amounts are shown in Table 3-10 and Table 3-11. The locations are shown 

in Figure 3-6, Figure 3-7, and Figure 3-8.
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-13

Table 3-10 Minnesota Utility PV Sites for Study Scenarios

Location Baseline Scenario 1 Scenario 2 

Total at 

each site

Riverton 230 2 5 5 12

Badoura 230 3 8 10 21

Hubbard 230 5 10 15 30

Wing River 230 5 10 15 30

	Alexandria 345 20 20 50 90

Quarry 345 30 80 110

Chub Lake 345 20 20 100 140

Prairie Island 345 30 100 130

North Rochester 345 30 100 130

Byron 345 20 20 100 140

Pleasant Valley 345 20 30 100 150

Sheas Lake 345 20 30 100 150

Owatanna 115 50 50

Wilmarth 345 50 100 150

Adams 345 20 30 100 150

Hayward 161 51 51

Cedar Mountain 345 20 30 100 150

Willmar 230 80 80

Big Stone South 345 20 30 100 150

Hazel 345 20 30 100 150

Lyon County 345 20 30 100 150

Fort Ridgley 115 50 50

Chanarambie 115 50 50

Fox Lake 161 50 50

Winnebago(Huntley) 345 30 40 100 170

Brookings 345 26 40 100 166

West New Ulm 115 50 50

Lakefield 345 30 40 100 170

Pipestone 115 50 50

Nobles 345 30 40 100 170

Split Rock 345 30 40 150 220

Ledyard, IA 345 40 200 240

Obrien, IA 345 40 200 240

Totals 361 723 2756 3840
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-14

Figure 3-6 MN Solar for Utility Locations - Baseline Figure 3-7 MN Solar for Utility Locations - All Scenarios
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-15

Table 3-11 MN Distributed PV Sites for Study Scenarios

Location Baseline Scenario 1 Scenario 2

Total at 

each site

NORTHERN HILLS 4 6 15 25

SOUTH FARIBAULT 2 4 9 15

CANNON FALLS 3 9 21 33

INVER HILLS 6 12 28 46

BLUE LAKE 4 9 18 31

GRE-MCLEOD 3 5 13 21

TERMINAL 9 34 30 73

PARKERS LAKE 14 24 92 130

AS KING 8 14 32 54

BLAINE 3 6 14 23

COON CREEK 8 10 24 42

DICKINSON 4 7 16 27

ELM CREEK 2 4 9 15

KOLMAN LAKE 4 7 16 27

BLAINE 4 7 16 27

ELK RIVER 4 7 16 27

ELM CREEK 2 4 9 15

CHISAGO 4 7 16 27

SHERBURNE CTY 3 5 13 21

RUSH CITY 2 3 7 12

PAYNESVILLE 3 7 16 26

Totals 96 191 430 717

MW (AC)
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-16

Figure 3-8 MN Distributed PV Sites

3.3.2 Non-Minnesota PV Solar

MISO solar was sited at ERGIS solar data set locations with a fixed 10%/90% split between 

Distributed PV and Central utility scale PV and this split was also determined in the stakeholder 

study scoping process.

 For the Baseline no solar was added.

 For Scenario 1, a total of 19 MWac of distributed PV was added.

 For Scenario 2, a total of 3,015 MWac PV was added with 135 MW being distributed and 2,880 

MW classified and sited as Utility scale solar. 

These solar generation amounts are shown in Table 3-12 and Table 3-13. The locations are shown 

in Figure 3-9.
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-17

Table 3-12 Non-MN Solar for Utility Locations 

State Baseline Scenario 1 Scenario 2 Total at 

each site

MW (AC)

Michigan 126 0 189 315

Indiana 239 0 521 681

Illinois 188 0 377 572

Iowa 39 0 55 94

Missouri 431 0 1583 2079

Arkansas 7 0 39 48

Kentucky 22 0 116 143

Totals 1052 0 2880 3932
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-18

Table 3-13 Non-MN Distributed Solar for Study Scenarios 

Baseline Scenario 1 Scenario 2 Sub-totals Totals

City

Detroit 0 1 6 7

Flint 0 0 4 4

Grand Rapids 0 1 6 7

Ann Arbor 0 1 6 7

Lansing 0 1 5 6

Indianapolis 0 1 6 7

Evansville 0 1 6 7

Fort Wayne 0 1 6 7

South Bend 0 0 5 5

Rockford 0 1 7 8

Champaign 0 1 6 7

Peoria 0 0 3 3

Springfield 0 1 3 4

Milwaukee 0 0 6 6

Madison 0 0 4 4

Kenosha 0 1 4 5

Green Bay 0 1 6 7

Des Moines 0 1 6 7

Cedar Rapids 0 1 5 6

Sioux City 0 1 5 6

Davenport 0 1 6 7

St Louis 0 1 6 7

St Charles 0 1 6 7

St Peters 0 1 6 7

O'Fallon 0 0 6 8

Totals 0 19 135 154 154

IN

Location

MW (AC)

IL

W i

IA

MO

MI

27

31

26

22

22

26
GE Energy Consulting MRITS Final Report

WIND AND SOLAR GENERATION SITING 3-19

Figure 3-9 Locations of Non-MN Solar - Utility Locations
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-1

4 TRANSMISSION SYSTEM CONCEPTUAL PLANS

In 2013, the Minnesota Legislation adopted a requirement that all electrical utilities and 

transmission companies in the state of Minnesota to conduct an engineering study to evaluate the 

impacts of raising Renewable Energy Standard (RES) to 40% by the year 2030 and to higher 

proportions thereafter. This Minnesota Renewable Energy Integration and Transmission Study 

reviewed the impacts on reliability and costs, including necessary transmission network upgrades,

of increasing the RES while maintaining system reliability. As part of this study, Excel Engineering, 

Inc. was asked to help by performing a Transmission System Conceptual Plan Study. This portion of 

the study was designed to use powerflow analysis to evaluate certain transmission configurations 

alongside the production modeling.

4.1 Study Assumptions and Methodology

4.1.1 Study Procedure

The Siemens Power Technologies, Inc. “PSS/E” digital computer powerflow simulation program was 

used for the steady state thermal analysis to identify the limiting facilities (lines or transformers) 

which were encountered as the power injection (generation output) was added at the sites of 

interest per the MRITS Wind-Solar Siting. Beyond the initial load scale-up to configure the models to 

2028, the analysis described in this report is based on the “generation to generation” method of 

modeling new generation resources; consistent with MISO evaluation practice; beyond the initial 

load scale-up to configure the models to 2028. The “generation to generation” method involves 

adding new generation and simultaneously backing down or turning off an equal amount of 

existing generation to keep the system balanced where generation equals load (plus system losses).

A conceptual transmission plan was developed with respect to the Baseline and each scenario. 

System reliability was determined by technical analyses performed under traditional transmission 

planning methods, criteria, and assumptions. Performance characteristics to be addressed include 

the steady-state performance of the following:

Contingency Analysis (powerflow)

• System Intact

• N-1

• Common Structures / Breaker failure (NERC TPL Category C2 & C5)

The local balancing authority areas indicated below were monitored and evaluated for contingency 

analysis.

Greater than 300 kV

• Wisconsin Electric Power

• ITC Midwest

• MidAmerican Energy Company

• Montana Dakota Utilities

• American Transmission Company
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-2

Greater than 200 kV

• Southern Manitoba Area:

o Facilities South of Winnipeg / Brandon to US border

Greater than 100 kV

• Xcel Energy

• Minnesota Power

• Southern Minnesota Municipal Power Agency

• Great River Energy

• Otter Tail Power

• Western Area Power Administration

• Dairyland Power Cooperative

• ITC Midwest (facilities in Minnesota)

o Northern Iowa Area: Facilities North of Sioux City / Fort Dodge / Iowa Falls / Waterloo / Dubuque into 

Minnesota

4.1.2 Models Employed

The study base models used were the 2023 Summer Off-peak (70% load) case and 2023 Summer 

Peak case from the 2013 MTEP series of models. These models represent the transmission system 

as it is presently anticipated to be configured in the year 2023. The models were then modified to 

create a 2028 Baseline model representation with the following additions:

All CapX2020 Group 1 Projects1

• Monticello-Quarry-Alexandria-Bison (Fargo) 345 kV line

• Brookings Co-Lyon Co-Cedar Mountain-Helena-Chub Lake (Lake Marion)-Hampton Corner 345 kV, 

Lyon Co-Hazel Creek 345 kV

• Hampton Corner-North Rochester-North La Crosse 345 kV line

• Wilton-Cass Lake-Boswell 230 kV line

All MISO Multi Value Projects (MVPs) approved in 2011 

• Big Stone South-Brookings 345 kV line

• Brookings Co-Lyon Co-Cedar Mountain-Helena-Chubb Lake (Lake Marion)-Hampton Corner 345 kV, 

Lyon Co-Hazel Creek 345 kV (same as shown in CapX2020 Group 1 Projects)

• Lakefield Jct.-Huntley-Ledyard-Kossuth-O'Brien & Kossuth-Webster 345 kV lines

• Ledyard-Colby-Killdeer-Blackhawk-Hazelton 345 kV line

• Briggs Road-North Madison-Cardinal & Dubuque Co.-Spring Green-Cardinal 345-kV lines

• Ellendale-Big Stone South 345 kV line

• Ottumwa-Adair 345 kV line

• Adair-Maywood-Palmyra 345 kV line

• Palymra-Maywood-Merleman-Meredosia-Ipava & Meredosia-Pawnee 345 kV lines

• Pawnee-Pana-345 kV Line

• Pana-Mt. Zion-Kansas-Sugar Creek 345 kV line

• Reynolds-Burr Oak-Hiple 345 kV

 

1

http://www.capx2020.com/, accessed 9/25/2014
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-3

• Michigan Thumb Loop Expansion 345 kV line

• Reynolds-Greentown 765 kV line

• Pleasant Prairie-Zion Energy Center 345 kV line

• Fargo-Maple Ridge-Oak Grove 345 kV Line

• Sidney-Rising 345 kV line

Other Transmission Projects

• MTEP Appendix A Projects with In-Service date Prior to 2023

• Manitoba Hydro Bipole III

• Antelope Valley Station-Charlie Creek-Williston-Tioga 345 kV

• Hazleton-Salem 345 kV

• Dorsey-Iron Range 500 kV (Great Northern Transmission Line)

• Increase Square Butte HVDC to 550 MW

• Center - Prairie 345 kV line

• Transmission Owner's transmission changes

o Winger-Thief River Falls 230 kV line

4.1.2.1 Load Scaling

The load was scaled up in the following areas to get to the 2028 proposed levels.

For Minnesota Utilities

• 0.5% Annually

• 590 MW

For other MISO North and Central Utilities

• 0.75% Annually

• 3460 MW

\

4.1.2.2 Generation Additions:

The following generation was included: All In-service and/or signed Generator Interconnection 

Agreements at the start of the analysis.

• Minnesota Power’s-Bison Wind 600 MW

• Manitoba Hydro’s Keeyask Hydro 695 MW

• Transmission Owner’s generation changes

All generation added from the MRITS Wind-Solar Siting were added by the following dispatch 

criteria of their nameplate value.

Summer Peak Model

• Wind – 20%

• Solar – 60%

Summer Off-Peak Model

• Wind – 90%

• Solar – 60%
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-4

The following switched shunt capacitors were added to all models at the following buses for 

additional voltage support. This was a broad and major addition necessary to build the Baseline 

model with the load and generation additions to keep the system near 1.0 p.u. voltage, in order to 

help meet existing MISO North/Central state RPSs. 

Switched shunt capacitors were added to all models at the following buses

• 400 MVAR @ Adams 345 kV bus 

• 300 MVAR @ Blackhawk 345 kV bus

• 200 MVAR @ Blue Lake 230 kV bus 

• 300 MVAR @ Colby 345 kV bus 

• 300 MVAR @ Eau Claire 345 kV bus 

4.1.3 Baseline Model

The following amounts of generation were added to the MTEP13 2023 models to obtain a Baseline 

model which meets the current MN RES and other MISO state RPSs.

4.1.3.1 MRITS Wind-Solar Siting 

Added beyond MTEP13 2023 models

• Total wind – 6900 MW

• Total Solar – 1509 MW

• MN Utility PV – 361 MW

• MN Distributed PV – 96 MW

• Non-MN Utility PV – 1052 MW

• Non-MN Distributed PV – 0 MW

Incremental Total – 8409 MW

4.1.4 S1 Model (Added beyond Baseline)

The following amounts of generation were added to the Baseline models to obtain an S1 model 

which would meet a 40% MN RES standard and existing RPSs in other MISO North/Central states.

4.1.4.1 MRITS Wind-Solar Siting

• Total wind – 1931 MW

• MN Wind – 1931 MW

• Non-MN Wind – 0 MW

• Total Solar – 933 MW

• MN Utility PV – 723 MW

• MN Distributed PV – 191 MW

• Non-MN Utility PV – 0 MW

• Non-MN Distributed PV – 19 MW

Incremental Total – 2864 MW
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-5

4.1.5 S2 Model (Added beyond S1)

The following amounts of generation were added to the S1 models to obtain an S2 model which 

would meet a 50% MN RES standard and a 10% RPS increase in other MISO states.

4.1.5.1 MRITS Wind-Solar Siting

 Total wind – 13636 MW

 MN Wind – 610 MW

 Non-MN Wind – 13026 MW

 Total Solar – 6201 MW

 MN Utility PV – 3840 MW

 MN Distributed PV – 717 MW

 Non-MN Utility PV – 3932 MW

 Non-MN Distributed PV – 154 MW

Incremental Total – 19837 MW

4.2 Results

4.2.1 SCED /MISO Footprint

4.2.1.1 Generation Dispatch Methodology

The models were built while incorporating the wind generation and solar generation within the 

MISO North and Central footprint. Some wind generation was added using the Security Constrained 

Economic Dispatch (SCED) which is similar to what is done when MISO creates a base MTEP model 

and this allows for generation re-dispatch for mitigating overloads. The SCED method determines 

how the generation resources participating in the market would be dispatched based on economics 

and reliability where the most cost effective resources are dispatched while maintaining system 

reliability. This effectively allowed the low-cost wind generation to remain on the system, while

other more expensive generation sources are turned down when needed to alleviate congestion. 

The remainder of the new generation added in the Baseline, S1 and S2 was dispatched in a manner 

consistent with the MISO Generation Interconnection studies and designated “Footprint Dispatch” 

and is described as, essentially scaling the whole footprint up and down to keep the swing bus 

within a certain range after the project under study was added. It is assumed that the swing bus is 

set based on where it started in the pre-project case. 

One of the purposes of the Multi-Value Project (MVP) portfolio was to provide delivery of wind 

resources needed to meet the MISO state Renewable Portfolio Standards (RPSs). Thus it was 

decided that for the Baseline case, the 6900 MW (3000+900+3000), deemed the “Multi Value Project 

wind” and which was required to meet the existing MN RES and other MISO state RPSs, would be 

dispatched in a SCED methodology and will utilize the MVPs for delivery into the MISO market. Once 

the Baseline model had been established by using SCED to alleviate constraints, the MISO footprint 

dispatch methodology was used to offset renewable generation additions in the S1 and S2 

scenarios. 
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-6

4.2.1.2 Baseline

The Baseline models were built incorporating the wind generation of 6900 MW dispatched by 

Security Constrained Economic Dispatch (SCED) methodology and the solar generation of 1509 MW 

dispatched across the MISO North and Central footprint. This process first involved adding the 6900 

MW of RGOS wind in 20% and 90% (of nameplate) dispatch amounts to the 2028 Summer Peak and 

Summer Off Peak models respectively and then having MISO run the SCED on these models. Wind 

plants were modeled at a ±0.95 power factor at the point of interconnection to the transmission 

system.

MISO performed the SCED on the models and provided the generation changes for the insertion of 

6900 MW of Baseline wind generation. These SCED models were then adjusted by adding750 MW of 

new hydro in Manitoba and then dispatching it to WPS (367 MW) and MP (383 MW) along with the 

1509 MW of Solar using the “Footprint Dispatch” method which yields the Baseline model. Note: the 

367 & 383 MW of hydro add up to 750 MW and are contractual amounts associated with the Great 

Northern Dorsey to Iron Range 500 kV project.

The following two Baseline models then were created.

S70 - Summer Off-Peak (70%) Baseline MRITS2028-S70-R17-Basea.sav

SUM - Summer Peak Baseline MRITS2028-SUM-R17-Basea.sav

Figure 4-1 shows how the bus angles for the Off-Peak condition in the Upper Midwest after

generation was added from the original 2013 MTEP 2023 model to the Baseline. In examining the 

bus angle figure, the larger the phase angle difference between points indicates higher power 

transfers, lower stability margins and more operational issues such as closing in lines after outages, 

etc. 

A very limited number of facilities were overloaded in the Baseline Scenario, so it was determined to 

be a good starting point for the study. See the Appendix for the full listing (available upon request 

from GRE).
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-7

Figure 4-1 Bus Angles from MRITS2028-S70-R17-Basea SCED Model

4.2.1.3 Scenario S1

Similar to some of the generation in Baseline, all of Scenario S1 generation was dispatched to the 

MISO footprint and the following models were created for S1 Scenario. 

S70 - Summer Off-Peak (70%) S1 MRITS2028-S70-R20-S1.sav

SUM - Summer Peak S1 MRITS2028-SUM-R20-S1.sav

Figure 4-2 shows how the bus angles change during the Off-Peak condition in the Upper Midwest 

as the generation was added from Baseline to S1. 

As shown in the Bus Angle figure, a bus angle change when moving from Northwest to Southeast is 

a little more extreme than in the Baseline model.
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-8

Figure 4-2 Bus Angles from MRITS2028-S70-R20-S1 Model0
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-9

Table 4-1 lists mitigation for identified overloads which were required for the S1 Scenario. See 

Appendices B4 and B6 for the full listing. All costs associated in this report are based on 2014 

planning level cost estimates with a ±30 % margin of error. 

Table 4-1 S1 Transmission Mitigation

Branch Possible Mitigation COST ($M)

Brookings Co-White 345 kV line WAPA terminal equipment- 1800 MVA 0.50

Cedarsauk-Edgewater 345 kV line ATC uprate- 750 MVA 1.00

Helena-Scott Co. 345 kV line XEL rebuild as double circuit 30.00

Ottumwa-Montezuma 345 kV line ITC uprate- 956 MVA 1.00

Split Rock-White 345 kV line WAPA terminal equipment- 1195 MVA 1.00

Riverton-Mud Lake 230 kV line GRE uprate- 383MVA 9.00

98L Tap-Hilltop 230 kV line MP rebuild - 400 MVA 11.20

Panther-Mcleod 230 kV line XEL uprate- 391 0.20

Willmar-Granite Falls 230 kV line GRE rebuild 391MVA 50.00

Hankinson-Wahpeton 230 kV line OTP uprate- 361 MVA 0.30

Briggs Road-Mayfair 161 kV line XEL rebuild- 400 MVA 10.00

Drager-Grand Junction 161 kV line CBPC rebuild- 326 MVA 37.50

Boone Jct-Fort Dodge 161 kV line MEC / CIPCO rebuild- 326 MVA 62.50

Hazleton-Dundee 161 kV line ITC terminal equipment- 326 MVA 0.20

Liberty-Dundee 161 kV line ITC rebuild- 326 MVA 6.50

Wabaco-Rochester 161 kV line DPC rebuild - 400 MVA 10.90

43L Tap-Laskin 138 kV line MP rebuild - 200 MVA 3.00

Wilmarth-Swan Lake 115 kV line XEL terminal equipment- 144 MVA 0.20

Wilmarth-Eastwood 115 kV line XEL uprate- 310 MVA 3.00

Souris-Velva Tap 115 kV line XEL terminal equipment- 144 MVA 0.20

Monticello-Oakwood 115 kV line XEL rebuild- 310 MVA 12.00

Black Dog-Wilson 115 kV line XEL terminal equipment- 310 MVA 0.20

Chisago-Lindstrom 115 kV line XEL upgrade- 400 MVA 0.50

Scott Tap-Scott Co. 115 kV line XEL Rebuild- 310 MVA 2.00

Hassan-Oakwood 115 kV line XL rebuild- 310 MVA 7.00

Velva Tap-McHenry 115 kV line XEL terminal equipment- 144 MVA 0.20

Hibbard-Winter St 115 kV line MP rebuild - 240 MVA 3.00

Etco-Forbes 115 kV line MP rebuild - 200 MVA 3.00

Forbes-Iron Tap 115 kV line MP rebuild - 200 MVA 3.00

Hibbing-44L Tap 115 kV line MP terminal equipment- 80 MVA 0.20
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-10

Branch Possible Mitigation COST ($M)

Iron Tap-Tbird 115 kV line MP rebuild - 200 MVA 3.00

Tbird-37L Tap 115 kV line MP rebuild - 200 MVA 3.00

Blackberry-Panasa Naswak 115kV MP upgrade- 240 MVA 2.16

Rugby OTP-Rugby CPC 115 kV line OTP rebuild - 200 MVA 1.00

Halliday-Beulah 115 kV line WAPA terminal equipment- 144 MVA 0.20

Rugby-Rugby CPC 115 kV line BEPC rebuild - 200 MVA 1.00

Johnson Jct-Morris 115 kV line GRE terminal equipment- 99 MVA 0.20

Johnson Jct-Ortonville 115 kV line OTP/MRES rebuild - 200 MVA 16.00

Fort Randall-Spencer 115 kV line WAPA terminal equipment 144 MVA 0.20

Blaisdell-Palermo 115 kV line BEPC rebuild - 200 MVA 8.00

Logan-SW Minot 115 kV line BEPC rebuild - 200 MVA 7.00

Hazel Creek 345/230 kV Tx #6 XEL add 2nd 336 MVA transformer 6.00

Stone Lake 345/161 kV Tx #9 XEL replace with 448 MVA transformer 7.50

Eau Claire 345/161 kV Tx #9 & 10 XEL replace BOTH with 448 MVA transformers 15.00

Lyon Co 345/115 kV Tx #1 XEL add 2nd 448 MVA transformer 7.50

McHenry 230/115 kV Tx #1 GRE replace with 187 MVA transformer 2.00

LaCrosse 161/69 kV Tx #1 & 2 XEL replace BOTH with 112 MVA transformers 3.20

Marshland 161/69 kV Tx #1 & 2 XEL replace BOTH with 112 MVA transformers 3.20

Gravel Isle 161/69 kV Tx #5 & 6 XEL replace BOTH with 112 MVA transformers 3.20

West Faribault 115/69 kV Tx #1 & 2 XEL replace BOTH with 140 MVA transformers 3.60

Paynesville 115/69 kV Tx #1 & 2 XEL replace with 70 MVA transformer 2.80

Prentice 115/69 kV Tx #5 XEL replace with 70 MVA transformer 1.40

Holcombe 115/69 kV Tx #1 DPC replace with 70 MVA transformer 1.40

Glendale 115/69 kV Tx #1 & 2 GRE replace Both with 112 MVA BOTH transformers 3.20

Add breakers at Arrowhead 115kV bus* 2.00

Total Cost 373.06

* To mitigate the contingencies that remove the full 115 kV bus sections, install a breaker-and-half scheme
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-11

The map in Figure 4-3 shows all the mitigation required to fix the transmission concerns for 

dispatching S1 generation to the MISO Footprint. The mitigations are spread throughout the study 

region.

Figure 4-3 S1 Transmission Mitigation Map

The S1 powerflow cases were repeated to verify transmission upgrade results and ensure that the 

mitigations didn’t cause subsequent cascading issue on the system. These mitigations are 

considered conceptual at this point and thus have not been optimized where, for example, one 

upgrade or a new facility may alleviate one or more of the identified overloads. Thus, further study 

would be required for the identification of the most practicable upgrade to alleviate these violations. 

These 54 mitigations could create a challenge in scheduling and coordinating outages for the 

construction time necessary to upgrade the facilities. 

4.2.1.4 S2 Scenario

The S2 Scenario generation could not be added or dispatched to the MISO footprint similar to 

Scenario 1 without making some changes and/or additions to the Scenario 1 models primary due to 

the large amount of renewable generation (17245 MW) being added to the model. The generation 

addition created an extensive number of violations during system intact conditions along with some 

extreme contingencies that were difficult to solve.
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-12

Figure 4-4 shows an extreme difference in how the bus angles change during the Off-Peak 

condition in the Upper Midwest as the generation is added from S1 to S2. 

Figure 4-4 Bus Angles from MRITS2028-S70-R19-S2 Model

4.2.2 Scenario 2

4.2.2.1 Transmission Expansion

In order to get the additional S2 17,245 MW of generation necessary to increase the MN RES to 50% 

and MISO states collectively to 25% into the case, the transmission expansion projects shown in 

were included. These expansions are also shown on the map in Figure 4-5. 

Figure 4-6 shows how the bus angles change during the Off-Peak condition in the Upper Midwest 

when added the S2 Transmission Expansion. The change occurs mostly in the area east and 

southeast of Minnesota.

The cases used with these changes were:

S70 - Summer Off-Peak (70%) S2 MRITS2028-S70-R19-S2-Trans.sav

SUM - Summer Peak S2 MRITS2028-SUM-R19-S2-Trans.sav
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-13

Table 4-2 S2 Transmission Expansion

Branch COST ($M)

Corridor Project (rebuilding existing 230 kV line to 345 kV) 

Hazel Creek-Panther-Mcleod-Blue Lake double circuit 345 kV line

466.00

Iron Range-Arrowhead 345 kV line 182.00

Sheldon-Eau Claire-Alma-Adams-Killdeer 345 kV line 700.00

Blackhawk-Montezuma 345 kV line 196.00

Big Stone South-Hazel Creek 345 kV line 200.00

Bison-Alexandria-Quarry-Monticello 345 kV line #2(dbl circuit CapX2020) 204.10

Brookings Co-Lyon Co 345 kV line #2(dbl circuit CapX2020) 58.00

Helena-Chub Lake-Hampton 345 kV line #2(dbl circuit CapX2020) 47.00

Hampton-North Rochester-Alma 345 kV line #2(dbl circuit CapX2020) 75.00

Total Cost $2,128.10

Figure 4-5 S2 Transmission Expansion Map
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-14

Figure 4-6 Bus Angles from MRITS2028-S70-R19-S2-Trans Model 

4.2.2.2 SCED and Top 4 to Bottom 10

Even after the transmission expansion was added to the models, there were still concerns with the 

amount of equipment overload violations in the model along with some outages not allowing the 

model to solve. The MRITS task force decided to perform SCED on the S2 cases with the S1 

mitigation and the S2 transmission expansion. MISO performed the SCED on models. The cases 

used for the S2 results were:

S70 - Summer Off-Peak (70%) S2 MRITS2028-S70-R19-S2-Trans-R2-SCED-A.sav

SUM - Summer Peak S2 MRITS2028-SUM-R19-S2-Trans-R2-SCED-A.sav

Based on the Production Cost Modeling results, it was noted that several of the wind generation 

sites from the MRITS Wind-Solar Siting were causing overloads in the thermal case were also 

congested and thus restricted in the production modeling. The MRITS TRC decided that the top 4 

congested non-Minnesota centric generation sites would have generation reduced and moved to 

the bottom 10 least congested non-Minnesota centric generation sites (T4B10) (as described in the 

Siting Section). The resulting new S2 cases were:

S70 - Summer Off-Peak (70%) S2 MRITS2028-S70-R19-S2-Trans-R2-SCED-A-T4B10.sav

SUM - Summer Peak S2 MRITS2028-SUM-R19-S2-Trans-R2-SCED-A-T4B10.sav
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-15

Figure 4-7 shows how the bus angles change during the Off-Peak condition in the Upper Midwest 

when the S2 Transmission Expansion is added with SCED of S2 generation and the Top4-Bottom10. 

Figure 4-7 Bus Angles from MRITS2028-S70-R19-S2-Trans-R2-SCED-A-T4B10 Model

In addition to the S2 Transmission Expansions ($2.128B from) and moving some wind generation 

from the top 4 congested sites to the bottom 10 least congested non-Minnesota centric generation 

sites, steady state thermal analysis results identified transmission mitigation for the S2. The S2 

additional mitigations are shown in Table 4-3. The locations are shown in Figure 4-8. See the 

Appendix for the full listing (available upon request from GRE).
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-16

Table 4-3 S2 Transmission Mitigation

Branch Possible Mitigation COST ($M)

Gardner Park-Sheldon 345 kV line ATC uprate to 1219 MVA 10.00

Sioux City-Twin Church 230 kV line NPPD rebuild 390 MVA 37.76

McHenry-Coal Creek Tap 230 kV line GRE rebuild 450 MVA 78.08

Lakefield-Dickenson Co. 161 kV line ITC Rebuild 400 MVA 26.75

Triboji-Dickenson Co. 161 kV line ITC Rebuild 400 MVA 3.00

Huntley-Freeborn 161 kV line ITC Rebuild 400 MVA 47.88

Webster-Wright 161 kV line MEC Rebuild 400 MVA 14.75

Alma-Lufkin 161 kV line DPC Rebuild - 400 MVA 31.50

La Crosse-Mayfair 161 kV line XEL Rebuild 400 MVA 4.63

Devils Lake-Ramsey 115 kV line GRE Uprate 120 MVA 0.50

Velva Tap-GRE McHenry 115 kV line XEL Rebuild310 MVA 5.20

Souris-Velva Tap 115 kV line XEL Rebuild310 MVA 19.60

Sheldon Pump-Osprey 115 kV line XEL Rebuild310 MVA 20.90

Osprey-Hawkin 115 kV line XEL Rebuild 310 MVA 14.00

Hutch McLeod-Hutchinson 3M 115 kV line GRE Rebuild 310 MVA 5.20

Hutch Muni-Hutchinson 3M 115 kV line GRE Rebuild 310 MVA 1.10

Sioux City 345/230 kV Tx 1 WAPA replace with a 2x336 MVA transformer 12.00

Stone Lake 345/161 kV Tx 9 XEL modified S1 mitigation, but adding a 2nd

336 MVA transformer rather than replacing

-

GRE McHenry 230/115 kV Tx #1 GRE replace with 224 MVA transformer 4.00

GRE Spring Creek 161/69 kV Tx #2 GRE replace BOTH with 112 MVA

transformers

3.20

Prairie 115/69 kV Tx #2 MPC add 69 kV breakers 2.00

GRE St. Boni 115/69 kV Tx #1 GRE replace with 112 MVA transformer 1.60

Split Rock 345/115 kV Tx # 11 XEL add 3rd 448 MVA transformer 7.50

Total Cost 351.14
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-17

As seen in Figure 4-8, the mitigations are spread throughout the study region and there is a 

recognition that there may have been more system overloads outside the study monitor area. 

Figure 4-8 Transmission Mitigation Map

The S2 powerflow cases were repeated to verify transmission upgrade results. The transmission 

expansions and mitigations are considered high-level and conceptual at this point and thus have 

not been intensively analyzed and compared with other alternative mitigations nor have the 

projects been optimized where, for example, one upgrade or a new facility may alleviate one or 

more of the identified overloads. 

Thus, further study would be required for the identification of the most practicable expansion or 

upgrade to alleviate these specific violations or widespread grid issues. These upgrades would 

require coordination with study and validation by MISO and other utilities. These 9 expansions and 

23 mitigations could create a challenge in scheduling and coordinating outages for the 

construction time necessary to upgrade and build the facilities. 

4.2.2.3 Production Cost Mitigation

Following the steady state power flow modeling which produced the transmission expansions and 

mitigations, Production Cost Modeling was performed to determine if any additional transmission 

facilities should be upgrades to help alleviate market congestion. This generation siting shift 

assisted in producing a more reliable and efficient market system. Table 4-4 lists mitigations from 

the production cost analysis. See the Appendix for the full listing (available upon request from GRE).
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-18

Table 4-4 S2 Transmission Mitigations from Production Cost Analysis

Branch Possible Mitigation COST ($M)

Blackhawk SW Yd-Colley Rd 138 kV line ATC Rebuild- 400 MVA 1.95

Adams 161/69 kV Tx #1 112MVA ITC replace with 112 MVA transformer 1.60

Huntley (Winnebago) 161/69 kV Tx #1 70 MVA ITC replace with 70 MVA transformer 1.40

NW Beloit-Paddock 138 kV line ATC Rebuild- 400 MVA 3.15

Hankinson-Wahpeton 230 kV line OTP Rebuild- 430 MVA 40.80

Wapello Co.-Jeff 161 kV line ITC Rebuild- 400 MVA 33.90

Blue Earth Tap-Huntley (Winnebago) 161 kV line ITC Rebuild- 400 MVA 5.25

Total Cost 88.05

Figure 4-9 Map of S2 Transmission Mitigations from Production Cost Analysis

4.2.2.4 HVDC Transmission

Given the large number and magnitude of 345 kV mitigations identified for Scenario 2, it was 

decided to conduct a mitigation sensitivity using a HVDC design to deliver the non-MN MISO wind 

located in western MISO to eastern MISO. This HVDC multi-terminal line design was guided by Bus 

Angles shown in Figure 4-4 in order to connect the HVDC terminals to the extreme angle differences 

(Red and Blue). The HVDC line was approximately 800 miles long and operated at 600 kVdc with 

two converter buses located at Brookings County and O’Brien County and two invertor buses 

located Breed (Sullivan) and Dumont. 
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-19

All runs were done only on the off-peak (S70) case and were not optimized in any form, but to be 

used as a reference. The line was tested at 2000, 2500, 3000 and 3500 MW. The cases used in the 

review were:

2000 MW MRITS2028-S70-R19-S2-HVDC-2000.sav

2500 MW MRITS2028-S70-R19-S2-HVDC-2500.sav

3000 MW MRITS2028-S70-R19-S2-HVDC-3000.sav

3500 MW MRITS2028-S70-R19-S2-HVDC-3500.sav

Figure 4-10 is a map showing the HVDC line location and the four terminals (red dots).

Figure 4-10 HVDC Transmission Map

The HVDC line transferred a significant amount of power from the converter terminals in the west, 

where a major amount of the MRITS Wind-Solar Siting were located at or near those terminals. If 

future wind would be developed further away from the HVDC terminals, the HVDC Transmission 

Expansion option would not be as efficient at transferring power from Western MISO to Eastern 

MISO and other transmission upgrades would likely be needed to get the new wind to the HVDC 

terminals. Contingency or Outage of the HVDC line as full, two-pole, or partial, single pole was not 

evaluated during this study. These outages would require an extensive study and thus was not 

conducted. We do know from previous work in this study that the ac transmission system could not 

accommodate all the S2 generation without some additional transmission, so some level of 

generation runback/tripping or ac transmission expansion would be required in the case of a single 

or double pole HVDC outage. The estimated cost for a four terminal 3500 MW HVDC for this 

distance would be approximately $3 Billion. See the Appendix for the full listing (available from GRE 

upon request).
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-20

An undetermined portion of the HVDC estimated cost could be allocated to central and eastern 

portions of MISO to help meet their respective RPSs. 

Table 4-5 lists the ac transmission mitigation required beyond S1 mitigation and the HVDC at 3500 

MW. This is an increase in $280M of mitigation beyond the S1 mitigations. This table does not 

include mitigations for the outage of the HVDC.

Table 4-5 S2 AC Transmission Mitigations required with HVDC Option

Branch Violation Contingency COST ($M)

Hazelton-Mitchell Co. 345 kV line ITC/ MEC Upgrade- 1464 MVA 201.60

McHenry-Coal Creek Tap 230 kV line GRE upgrade- 637 MVA 78.08

McHenry-Balta 230 kV line GRE upgrade- 480 MVA 69.44

Big Stone-Big Stone South 230 kV line OTP upgrade- 831 MVA 5.00

Oakes-Ellendale 230 kV line OTP upgrade- 480 MVA 38.40

Blair-Watertown 230 kV line WAPA upgrade- 480 MVA 46.40

Briggs Road-Mayfair 161 kV line XEL upgrade- 434 MVA 10.00

Lacrosse-Mayfair 161 kV line XEL upgrade- 434 MVA 4.63

Wheaton-Elk Mound 161 kV line XEL upgrade-434 MVA 4.50

Beaver Creek-Adams 161 kV line DPC upgrade- 434 MVA 18.88

Wabacco-Alma 161 kV line DPC upgrade- 434 MVA 25.38

Swan Lake-Fort Ridgely 11 kV line 5 XEL upgrade- 232 MVA 13.20

Franklin-Redwood Falls 115 kV line XEL upgrade- 232 MVA 12.80

MN Valley-Redwood Falls 115 kV line XEL upgrade- 232 MVA 27.80

Lawrence Creek-Shafter 115 kV line XEL upgrade- 350 MVA 6.10

Lindstrom-Shafer 115 kV line XEL upgrade- 319 MVA 2.80

Big Stone-Highway 12 115 kV line OTP upgrade- 319 MVA 2.00

Highway 12-Ortonville 115 kV line OTP upgrade- 319 MVA 4.50

Hoot Lake-Fergus Falls 115 kV line OTP upgrade- 232 MVA 4.20

OTP Forman-WAPA Forman 115 kV line OTP upgrade- 232 MVA 0.20

Devils Lake SE-Ramsey 115 kV line OTP upgrade- 232 MVA 0.20

Aberdeen Jct-Ellendale 115 kV line NWE upgrade- 232 MVA 39.00

Iron Range 500/230 Tx MP upgrade- 1043 MVA 0.00

Forman 230/115 Tx WAPA replace w/ 180 MVA transformer 2.00

Big Stone South 345/230 Tx #1 & 2 OTP replace BOTH w/ 800 MVA transformer 15.00

Big Stone South 230/115 Tx OTP replace with 390 MVA transformer 6.00

Total Cost 630.60
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TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-21

4.3 Conceptual Transmission Conclusions

The model building for the steady state thermal analysis involved significant transmission and 

generation additions and load increases to reflect the Baseline assumptions of the present MISO 

state RPSs in a 2028-2030 timeframe along with the planned transmission and generation buildouts.

The generation dispatch involved a combination of methodologies to best represent the future 

system grid which accommodated the lowest fuel cost generation units and future contracts while 

maintaining system reliability.

The Scenario 1 Transmission Mitigations, as identified with steady state thermal powerflow analysis, 

to accommodate an increase wind and solar generation necessary to increase the MN RES to 40% 

involved 54 facilities with a total estimated cost of $373M. 

The Scenario 1 mitigations are considered conceptual at this point and thus have not been 

optimized and thus further study would be required for the upgrading/mitigation of these violations. 

These 54 mitigations could create a challenge in scheduling and coordinating outages for the 

construction time necessary to upgrade the facilities. 

To reliably accommodate the addition of 17,245 MW of Scenario 2 generation necessary to increase 

the MN RES to 50% and MISO states collectively to 25% into the case and alleviate widespread 

system issues, a significant amount of transmission expansions were identified and included in the 

S2 models. These expansions involved 9 facilities with a total estimated cost of $2,128M.

Even with the S2 expansions identified above, there were still concerns with the high number of 

facility overloads and violations, it was noted that several of the wind generation sites from the 

MRITS Wind-Solar Siting were causing market congestion and it was decided that the top 4 

congested non-Minnesota centric generation sites would have generation reduced and moved to 

the bottom 10 least congested non-Minnesota centric generation sites (T4B10). This generation 

siting shift assisted in producing a more reliable and efficient market system.

In addition to the S2 Expansions and moving some wind generation from the top 4 congested sites 

to the bottom 10 least congested non-Minnesota centric generation sites, steady state thermal 

powerflow analysis still identified Scenario 2 Transmission Mitigations, involving 23 facilities with a 

total estimated cost of $351M. 

The Production Cost Modeling & Analysis showed market congestion caused by the overload of 

several facilities. These congestion points in the MN Centric area were selected for mitigation and 

these involved 7 facilities with a total estimated cost of $88M.

The total Scenario 2 expansions and upgrades involved 39 projects at an estimated cost of 

$2,567M. The cost of the Scenario 1 mitigations should be added to the S2 costs in order to 

accommodate a MN RES of 50% and a MISO collective RPS of 25%. It should be noted that an 

undetermined portion the S2 transmission expansions and upgrades are likely due to the non-MN 

MISO renewables and not exclusively for the MN renewables. No effort was made to separate these 

costs into those assigned to MN Renewables and those to non-MN MISO renewables.
GE Energy Consulting MRITS Final Report

TRANSMISSION SYSTEM CONCEPTUAL PLANS 4-22

Table 4-6 Scenario Transmission Cost Breakdown

An alternative to the above expansions and mitigations, a high level HVDC line was tested as a 

sensitivity. The modeled 600 kV HVDC line was about 800 miles long and with converter buses 

located at southeastern South Dakota and northwest Iowa and two inverter buses located northern 

and southern Indiana. The estimated cost of this HVDC project was approximately $3B and still 

required 26 mitigations with an estimate cost of approximately $631M for a total HVDC portfolio 

cost of approximately $3.6B, which is approximately a 40% increase over the ac mitigation 

portfolio). 

The transmission expansions and mitigations are considered high-level and conceptual at this point 

and thus have not been intensively analyzed nor optimized thus, further study would be required for 

the identification of the most practicable expansion or upgrade and would likely change as the 

wind is actually developed. These upgrades would require coordination with MISO and other 

utilities. These transmission expansions and mitigations could create a challenge in scheduling and 

coordinating outages for the construction time necessary to upgrade and build the facilities. 

This study builds upon several previous state mandated renewable related studies and the analysis 

and results have demonstrated the regional nature and benefits of the grid and the operating 

market.

Expansion 

Costs ($M)

Mitigation 

Costs ($M)

Market 

Mitigation 

Costs ($M)

Total Costs 

($M)

Scenario 1 $0 $373 $0 $373 

Scenario 2 $2,128 $351 $88 $2,567 
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DYNAMIC SIMULATION MODEL 5-1

5 DYNAMIC SIMULATION MODEL

This section documents the data source for the dynamic modeling, benchmarking of the model, 

modifications made to represent the future high-renewable scenarios and criteria for evaluating 

stability simulations.

5.1 Data Sources and Benchmarking of Dynamic Models

The original data for dynamic analysis provided by the Minnesota utilities was based on an MTEP

2013 data set. The following files were provided:

Powerflow data in PSS/E raw data format: 2023_SH_2013DPP_August_Pre-DPP.raw

Case comments:

2023 SHOULDER LOAD CASE

AUG 2013 DPP BASE CASE, PRE DPP

Dynamic data in PSS/E dyre data format: 2018_final_2.dyr

Contingency description files provided in PSS/E response file (.idv) format

These files were converted to GE PSLF format and tested by simulating the benchmark 

contingencies listed in Table 5-1. Simulations were compared to results obtained using a similar 

database in PSS/E. Simulation results were reviewed with the MRITS Technical Team. After some 

minor modifications to the dynamic data (adding mechanically switched capacitor models), the 

benchmarking results were deemed acceptable. 

Note that the PSLF model does not include custom HVDC controls. Rather, it represents a typical 

HVDC system. Simulation results were reviewed by Technical Team members to ensure that the 

simulated HVDC response represented expected response. In particular, commutation failure and 

blocking was reviewed for disturbances near the HVDC terminals.
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DYNAMIC SIMULATION MODEL 5-2

Table 5-1 Benchmark Contingencies

Name Description 

EI2 CU HVDC Permanent Bipole fault with tripping of both Coal Creek units.

AG1 SLG fault with breaker fail at Leland Olds on the Ft. Thompson 345 kV line

AG3 3 phase fault at Leland Olds on Ft. Thompson 345 kV line, Clear both ends of the line in 4 cycles 

NAD 4cycles 3 phase fault on the Dorsey to Forbes 500 kV line D602F at Forbes. Runback bi-poles that 

terminate at Dorsey

PCS SLG fault t with breaker fail at King with 8P6 stuck. Trips King-EauClaire-Arpin and King-Chisago 

345 kV line

5.2 Dynamic Load Model

After obtaining acceptable benchmarking results, the dynamic data set was modified to include a 

more detailed representation of the study area loads. The objective of adding a dynamic load 

model was to capture possible fault-induced delayed voltage recovery issues caused by reduced 

synchronous generation.

The GE PSLF composite load model CMPLDW was added at all loads greater than 5 MW throughout 

MISO. The topology of the composite load (shown in Figure 5-1) is intended to give more realistic 

representation of dynamic load behavior than present practice. The model adds distribution 

transformer and feeder for each load. The load is then modeled at the distribution bus as a 

composite of different induction motors, electronic load and static load.

In order to develop parameters for the load model, the Minnesota utilities classified all loads in their 

service territory. Classifications for non-industrial loads are shown in Table 5-2. Classifications for 

industrial loads are shown in Table 5-3. Loads not identified by the Minnesota utility were assumed 

to be either power mixed residential/commercial, or power plant auxiliary. Power plant auxiliary 

loads were assumed if the load was at a generator bus with a rated voltage less than 30 kV. 

The load characteristics used for each individual load were based on the load type using the WECC 

parameters. In total, the CMPLDW model was added to 2045 loads (37.8 GW for the shoulder 

period). Note that a different set of parameters was used for the light and shoulder load cases and 

the peak load case. This was intended to represent the higher level of motor load, particularly air 

conditioning, during the summer peak load than during spring and fall.

The parameters of the four equivalent motors are particularly important for dynamics, as the 

tendency for motor groups to stall (or not) during major voltage depressions has a substantial 

impact on system stability. One of the key features of the composite load model includes the ability 

to control whether stalled motors trip (by contactors opening) or continue to stay attached drawing 

starting current. Since the motor stalling behavior in the composite load has such a major and 

acutely non-linear effect on stability results, for this study, all motor tripping in the composite model 

is disabled. This is very conservative, and it allows for simpler and more illuminating comparison 

between dynamic simulation cases. 
GE Energy Consulting MRITS Final Report

DYNAMIC SIMULATION MODEL 5-3

Figure 5-1 GE PSLF Composite Load Model CMPLDW

Table 5-2 Non-industrial Load Types

ID Feeder Type Residential Commercial Industrial Agricultural

RES Residential 70 to 85% 15 to 30% 0% 0%

COM Commercial 10 to 20% 80 to 90% 0% 0%

MIX Mixed 40 to 60% 40 to 60% 0 to 20% 0%

RAG Rural 40% 30% 10% 20%
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DYNAMIC SIMULATION MODEL 5-4

Table 5-3 Industrial Load Types

ID Feeder Type

IND_PCH Petro-Chemical Plant

IND_PMK Paper Mill – Kraft process

IND_PMT Paper Mill – Thermo-mechanical process

IND_ASM Aluminum Smelter

IND_SML Steel Mill

IND_MIN Mining operation

IND_SCD Semiconductor Plant

IND_SRF Server Farm

IND_OTH Industrial – Other

AGR_IRR Agricultural irrigation loads

AGR_PMP Large pumping stations with synchronous motors

PPA_AUX Power Plant Auxiliary

5.3 2028 Study Data Sets

The original MTEP data set represented a 2023 shoulder load condition. This data set was modified 

to establish the 2028 light load, shoulder load and peak load cases. This involved adjusting the load 

in the MISO areas appropriately to represent 2028 conditions and adding the conceptual 

transmission plans identified in the thermal and voltage analysis. In going from shoulder load 2023 

to 2028, a 0.5% annual load growth was assumed for Minnesota and 0.75% annual load growth 

was assumed for rest of the MISO. The load in the 2028 shoulder case was then modified to 

develop a 2028 light load and 2028 peak load case. The new wind and solar generation for each 

scenario (baseline, S1 and S2) were then added to the 2028 cases. 

5.4 Dynamic Models for Renewables

The powerflow topology was modified to interconnect the new wind and utility-scale PV plants and 

distributed PV. These new plants have two transformations, one for the substation transformer and 

an equivalent for the unit transformer (from collector voltage to inverter voltage) with an 

intervening equivalent of the collector system. The arrangement is shown in Figure 5-2. 

For dynamic modeling, the utility-scale PV plants are modeled with full four quadrant dynamic 

models (based on the Type 4 wind turbine generator [WTG] model) with voltage regulation and 

zero-voltage ride-through (ZVRT). The utility-scale PV plants are modeled with a power factor of 

±0.90 at the inverter transformer. This gives an MVA rating of 1.11 times the plant MW rating, and 

reactive capability of ±0.436pu, based on the MVA rating. New wind plants were split roughly 50/50 

between Type 3 double fed asynchronous generator (DFAG) and Type 4 (full converter) with voltage 

regulation and ZVRT. The new wind plants are modeled with a power factor of ±0.90 at the 690V 
GE Energy Consulting MRITS Final Report

DYNAMIC SIMULATION MODEL 5-5

bus. This gives an MVA rating of 1.11 times the plant MW rating, and reactive capability of 

±0.436pu, based on the MVA rating. Both wind and utility-scale PV were set to regulate the 690 V 

terminal bus. Although advanced WTG controls such as inertial response and frequency response 

were available in the models, they were assumed to be inactive. Furthermore, they were not 

required for mitigation during the dynamic analysis task.

Distributed PV was modeled as lumped generation in central locations, based on the siting work. 

The distributed PV was modeled with no reactive/voltage regulation capability. The ability of the 

distributed PV generation (DPV) to ride through voltage and frequency excursions is handled by a 

separate logic. The model allows selection of different levels of voltage and frequency excursion 

that will result in the DPV blocking. A further part of the logic allows specification of how much DPV

will recover if the excursion returns within the user input bounds. The result is a high level of 

flexibility for modeling fault ride-through. However, the model does not support user input time 

delays on the blocking functions, and so is limited in its ability to reflect deliberate time thresholds 

for tripping (e.g., of the type in NERC low voltage ride through (LVRT) and IEEE 1547 standards). 

Voltage ride through settings used for the DPV maintained full PV output between 0.90 pu and 1.10 

pu voltage. Between 0.90 pu and 0.88 pu voltage, the DPV active power is run back linearly to zero. 

Below 0.88 pu voltage the PV is blocked. When voltage recovers above 0.9 pu the active power is 

restored. Similar logic is used for high voltage conditions between 1.1 and 1.2 pu. 

Frequency ride through/blocking was modeled similar to voltage ride through/blocking. The DPV

retains full output between 59.70Hz and 60.30 Hz. Between 59.70 Hz and 59.50 Hz the DPV active 

power runs back and is fully blocked below 59.5 Hz. However, unlike the voltage ride-through 

function, the PV active power does not recover after being blocked due to high or low frequency. 

There were no time delays model for the voltage or frequency ride through/blocking logic.

Figure 5-2 Renewable generation topology in powerflow Model

5.5 Monitoring Models and Performance Metrics

In order to quantify the effect of increased renewable generation on the system performance, 

several sets of metrics are developed. The metrics are geared towards identifying first swing 

stability, power swing damping and voltage response and recovery following a fault. Rotor angle of 

generators in the entire Eastern Interconnect are monitored to ensure if the system is transiently 

stable following each disturbance. Voltages are monitored for 220 kV and above buses throughout 

MISO.

In addition, a region-wide monitoring approach is used to identify issues that are not apparent from 

traditional stability plots. In this regard, a new dynamic model is developed to monitor regional 

performance. Regional metrics include measures such as, total rated MVA, rated MW, actual MW 
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DYNAMIC SIMULATION MODEL 5-6

and MVAR and reactive reserves for on-line synchronous generation and renewable generation. 

System measures such as regional load and interface flows are also monitored. The regional 

synchronous generation provides information about the short circuit strength of the region while 

the regional load and generator reactive power provides the understanding about regional voltage 

recovery following a disturbance. The percentage non-synchronous generation is also calculated 

from these measurements. These metrics are monitored dynamically and used to compare the high 

renewable system performance under various load conditions.

The geographical sub-regions and corresponding boundaries are defined based on the group of 

geographically coherent machines regardless of ownership and state boundaries. Altogether ten 

geographical subregions are defined for the study wherein six subregions constitute Minnesota 

Centric Region. Figure 5-3 shows the geographical subregion mapping with the regions shaded 

green being the Minnesota-Centric region. The assignment was confirmed after discussion with 

Technical Team members. The subregion assignment is used to evaluate the production simulation 

(Plexos) output for challenging periods as well as for obtaining the regional metrics for dynamic 

simulation. The geographical subregion is assigned to every generator in the entire Eastern 

Interconnect. Furthermore, all equipment including buses, generators, loads, lines, transformers are 

assigned subregion based on where they fit in the map shown in Figure 5-3. Table 5-4 lists the 

subregions and the names used to identify them.

Figure 5-3 Geographical subregions
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DYNAMIC SIMULATION MODEL 5-7

Table 5-4 Sub region assignment

Sub-Region No. Name

1 Iowa

2 North Dakota

3 Northern Minnesota

4 South Dakota

5 South & Central Minnesota

6 SW Minnesota

7 Nebraska

8 Wisconsin & Illinois

9 Manitoba

10 Outside

A generic impedance relay model is used on all 220 kV and above the transmission lines throughout 

Eastern Interconnect. This model is used only for monitoring purpose and will not trip the lines in 

response to post fault voltage and current. 

The instantaneous primary protection zone (Zone 1) is set to cover 85% of the primary line length. 

Zone 2 protection is delayed by 0.5 seconds and set for 125% of the primary line length. This model 

was used to identify possible system separation and voltage collapse issues in regions that were 

not explicitly monitored.

Figure 5-4 shows voltage performance criteria used by WECC. Worst conditions analysis is carried 

out to identify critical buses with respect to voltage dip and fault induced delayed voltage recovery. 

All 220 kV and above buses throughout MISO are monitored. With the idea of capturing large post 

fault transient voltage dip, buses with voltage dip below 20% of initial value for more than 20 cycles 

are identified. Another criterion is used to screen buses with voltage below 0.7 p.u. after fault 

clearing. In order not to capture low voltage during stuck breaker faults, where the fault clearing 

times are longer, the latter criterion is applied 0.15 sec after fault application.
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DYNAMIC SIMULATION MODEL 5-8

Figure 5-4 Voltage performance metrics
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PRODUCTION SIMULATION MODEL 6-1

6 PRODUCTION SIMULATION MODEL

6.1 Overview of Production Simulations

The Minnesota Renewable Energy Integration and Transmission Study (MRITS) analyzed three 

scenarios (Baseline, S1, and S2). The baseline scenario represents the generation, transmission and 

market system in 2028 if current industry and economic trends continue. S1 represents a future 

where baseline trends continue, along with Minnesota increasing its renewable penetration to 40% 

along with small Non-MN distributed solar in MISO. S2 represents a future where baseline trends 

continue, along with Minnesota increasing its renewable penetration to 50%, and MISO 

North/Central increases its renewable penetration to 25%. 

PLEXOSTM, an integrated energy model, was used to do the production simulations. The PLEXOS 

model was constructed from the existing 2013 MTEP Business As Usual (BAU) dataset for the study 

year 2028. Then S1 was built from the Baseline by adding new wind and solar generation and 

transmission upgrades, and S2 was built from S1 by adding yet more wind and solar generation, 

removing some expansion gas generation and adding additional transmission. 

6.2 PLEXOS Overview

PLEXOS was chosen because it can utilize a Day-Ahead Security Constrained Unit Commitment 

(SCUC) and Real-Time Security Constrained Economic Dispatch (SCED) interleaved market dispatch 

solution. This type of interleaved modeling, with one simulation feeding into the other, more 

accurately captures the forecast uncertainties realized between a Day-Ahead and Real-Time 

markets. Modeling the forecast uncertainty becomes increasingly important when dealing with 

significant levels of wind resource output which tends to be more stochastic in nature. 

Performing an economic production simulation was a principal aspect of the MRITS study to 

correctly model how the MISO system operates. The vast amount of hourly output such an analysis 

generates can be crucial in understanding which time periods are the most significant to analyze 

further. It also provides valuable insight into transmission system utilization, power system flows,

and renewable unit curtailment.

6.3 MRITS Production Simulation Model – Source Dataset

MISO used the 2013 MTEP Business as Usual (BAU) future as the source dataset (starting point) for 

the MRITS analysis. The BAU future is considered the status quo future and continues current 

economic trends. This future models the power system as it exists today with reference values and 

trends. Renewable portfolio standards vary by state and 12.6 GW of coal unit retirements are 

modeled. The MTEP futures are created by MISO and vetted by the MISO Planning Advisory 

Committee (PAC) stakeholder committee. Information for the dataset is sourced from Ventyx and 

updated through an extensive internal MISO process to bring it into line with the most current data. 

The PLEXOS model footprint includes all areas in the Eastern Interconnect, with the exception of 

Florida, ISO New England and Eastern Canada as shown in Figure 6-1. Figure 6-2 shows the MISO 

market footprint. MISO is modeled using membership information dated as of January 2014.
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PRODUCTION SIMULATION MODEL 6-2

Figure 6-1 Study Footprint

Figure 6-2 MISO’s Market Footprint
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PRODUCTION SIMULATION MODEL 6-3

As part of the MTEP BAU future development process, capacity was added to meet the various 

planning reserve margin requirements. Renewable resources were added to meet the various state 

renewable portfolio standards, shown in Figure 6-3, throughout the Eastern Interconnect. 

Also between 2013 and 2028, 24,900 MW of capacity was added to MISO to meet the planning 

reserve margin (14.2%), and 12,200 MW of coal was retired in MISO due to the forecasted effects of 

prior EPA regulations as shown in Figure 6-4. This does not include coal plant retirements that may 

result from the EPA’s proposed Clean Power Plan (111d).

Capacity additions include wind and demand side resources to meet state mandates along with 

gas units because of the low natural gas price. Demand and Energy Growth Rate was 1.06%, and all 

prices escalate at an inflation rate of 2.5%.

Wind and solar plant output was modeled at specific locations with each site having a unique 

historically based output as demonstrated in Figure 6-5.

1.

Figure 6-3 State Renewable Portfolio Standard Policies used in the MTEP13 Model

 

1

http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0
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PRODUCTION SIMULATION MODEL 6-4

Figure 6-4 MISO’s MTEP13 BAU capacity additions and coal Retirements

before changes were made as shown in Figure 6-6 (2013-2028)
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PRODUCTION SIMULATION MODEL 6-5

Figure 6-5 Illustration of site specific renewable output

6.3.1 Baseline Scenario

MRITS held slightly different assumptions than the 2013 MTEP BAU future, thus the baseline 

database needed to be modified to reflect these new assumptions. Wind resources used the same 

assumptions that the MTEP BAU future did, but solar units were adjusted. The forecasted solar units, 

totaling 1725 MW, in MISO were removed and 1509 MW of new solar generation was added to the 

Baseline model per MRITS assumptions. 

The siting locations of these units were also changed to reflect a more realistic distribution of solar 

resources which is explained in the Siting Section. A proxy expansion hydro unit in Manitoba Hydro 

was removed and replaced with Keeyask, a 695MW unit that has become certain (approved and 

under construction) since the 2013 MTEP models were built. The 500kV Great Northern transmission 

line was also added to deliver this hydro power.

6.3.2 Scenarios 1 and 2 

Scenario 1 and 2 had different capacity assumptions than the baseline case did so a new capacity 

expansion was done to reflect these different assumptions. Renewable capacity was increased and 

thermal capacity was decreased to maintain the same capacity reserve margins as shown in Figure 

6-6. The treatment of capacity credit for wind and solar resources is discussed in the following 

subsection.

Thermal capacity was not reduced for Scenario 1 because capacity reserves were slightly over the 

requirement in 2028 given the lumpiness of capacity additions, in other words, the generation is not 
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PRODUCTION SIMULATION MODEL 6-6

added in smooth incremental amounts but rather the generation is added in larger blocks. In 

scenario 2, enough renewables were added to warrant the reduction in thermal capacity.

Figure 6-6 Resource Capacity Changes for Scenarios 1 and 2

6.3.3 Capacity Credit for Wind and Solar Resources

A capacity credit value was needed for the wind and solar renewables in order to perform the 

resource forecasting capacity expansion. For each of those resource types a currently developed 

MISO process was utilized to determine what capacity value to use for the MRITS study. 

The resulting capacity credit values were:

Baseline and S1 Wind: 14.1%

S2 Wind: 11.8%

Solar: 40 %

6.3.3.1 Wind Capacity Value

For the wind capacity credit, this study referred to the MISO report2 findings.

Both the Baseline and Scenario1 models used the value of 14.1% of nameplate. Those cases both 

have levels of wind energy penetration, 14% and 15.2% respectively, which are close to the current 

MISO system amount of 13%, installed. 

 

2

Planning Year 2014-2015, Wind Capacity Credit, 

https://www.misoenergy.org/Library/Repository/Study/LOLE/2014%20Wind%20Capacity%20Report.pdf
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PRODUCTION SIMULATION MODEL 6-7

But for Scenario 2 which had a significant increase in the MISO penetration of wind to 23.8%, the 

Figure 6-7 from the report3 was used to interpolate a capacity value of 11.8% for wind. In the 

higher wind penetration regions, 15%+, as the figure shows, the wind capacity credit decreases due 

to a saturation of wind energy during peak times. Note that the figure shows only the 20 GW and 

30 GW penetration data points and these were converted to 21.2% and 31.8% penetration, 

respectively, based on the 94,298 MW 2013 MISO Peak Load used for that figure.

6.3.3.2 Solar Capacity Value

For the solar capacity value, this study referred to the MISO Resource Adequacy Business Practice 

Manual4 rules for non-wind, intermittent resources. The manual5 indicates that the following be 

used:

“Intermittent Generation and Dispatchable Intermittent Resources that are not powered by 

wind must supply MISO with the most recent consecutive three years of hourly net output (in 

MW) for hours 1500 – 1700 EST from June, July and August. For new resources, or resources 

on qualified extended outage where data does not exist for some or all of the previous 36 

historical months, a minimum of 30 consecutive days’ worth of historical data during June, 

July or August for the hours of 1500 - 1700 EST must be provided.”

So using only data during that prescribed time period and the 2006 NREL solar set of information 

provided for the sites used in the MRITS study, a capacity value of 40% of solar nameplate was 

calculated based on the capacity factor deterministic approach.

Figure 6-7 Plot of Wind Capacity Credit versus Penetration Level, from MISO Report

 

3

https://www.misoenergy.org/Library/Repository/Study/LOLE/2014%20Wind%20Capacity%20Report.pdf

4

https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=19206

5

Ibid. Section 4.2.2.1 (page-34) 
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PRODUCTION SIMULATION MODEL 6-8

The 40% capacity factor for solar was used in the resource forecasting step when determining 

which and how many other non-renewable resources to add to maintain the planning reserve 

margin in the future year.

For the load-flow analysis, it was decided to further stress the transmission system with a higher 

value of solar output beyond its capacity factor rating. A scatter plot of wind vs. solar output was 

compiled which can be seen in Figure 6-8. This figure shows that when the wind output is in the 

range of 20% as during peak load-flow type conditions or when it’s at a 90% range during off-peak 

load-flow type conditions, solar output could be in the high range of 60%. Based on that high range 

level value, 60% was chosen as the load-flow assumption level for solar.

Figure 6-8 Scatter Plot of Wind versus Solar Output

6.3.4 Forecast Uncertainty

The MRITS study incorporates wind, solar and load uncertainty to more accurately reflect the 

challenges associated with large scale renewable integration. Renewable profiles were provided by 

the National Renewable Energy Lab (NREL).

Wind uses the NREL EWITS wind dataset: Unit commitment uses the 4-hour ahead wind profile

Dispatch uses the actual wind site output

Solar uses the NREL ERGIS solar dataset: Unit commitment uses a MISO aggregate solar profile.

Dispatch uses the actual solar site output

Load uses historic load data: Unit commitment uses a stochastic load profile. 

Dispatch uses the historic actual profiles
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PRODUCTION SIMULATION MODEL 6-9

6.3.4.1 Wind

All 2006 wind data comes from the NREL EWITS wind data set. Two separate wind forecasts were 

considered, the Next Day (ND) and the 4-hour ahead (4HR) as shown in Figure 6-9. The plot shows 

normalized traces of hourly wind power for one week. The 4 hour wind forecast provided by NREL 

was used as this more accurately approximates the final generation commitment MISO would have

going into the Real Time market. The Actual output is the estimated wind that was actually 

produced for the given hour as provided by NREL6..

Figure 6-9 Sample of Hourly Forecast and Actual Wind Site Output (1st week of July)

 

6

http://www.nrel.gov/electricity/transmission/wind_integration_dataset.html
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PRODUCTION SIMULATION MODEL 6-10

6.3.4.2 Solar

Actual real time solar data comes from NREL. It is a combination of Eastern Renewable Generation 

Integration Study (ERGIS) data for non-Minnesota sites and newly created data for Minnesota sites. 

The forecast is created by summing all profiles together and creating a single shape for the entire 

region. This shape is scaled back down to the size of each individual solar site. 

The forecast will take into account wide spread cloudiness since it is the aggregate of the actual 

profiles, but spotty clouding will be washed out because of the aggregation. The solar arc can be 

perfectly forecasted but cloud cover creates the uncertainty in the forecast. 

Figure 6-10 shows the output of 2 Solar Sites, and demonstrates the differences between individual 

locations, and how they each compare to the forecast. Solar output is shown as a percentage of its 

Direct Current rating.

Figure 6-10 Sample of Hourly Forecast and Actual Solar Site Output (1st week of July))
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PRODUCTION SIMULATION MODEL 6-11

6.3.4.3 Load

Actual load profiles are historic 2006 shapes. Forecasts are created by compiling statistics from the 

MISO market between 2008 and 2011 and applying those to the actual shapes. A random draw was 

done using these statistics to simulate the historic differences between the forecast and the actual 

load. The day-ahead load forecast was used and not a 4-hour forecast because the day-ahead is a 

discrete and separate forecast while the 4 hour is simply a snapshot of the rolling forecast. 

Figure 6-11 shows a sample of load for a week, along with the random draw forecast which was 

used for this study.

Figure 6-11 Sample Minnesota Load Output (1st week of July)
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OPERATIONAL PERFORMANCE RESULTS 7-1

7 OPERATIONAL PERFORMANCE RESULTS

7.1 Scenarios for Production Simulation Analysis

As described in Chapter 2, the study was designed to evaluate scenarios with three levels of 

renewable energy (RE) penetration in Minnesota (see Table 7-1). These 3 levels of RE penetration

were analyzed with five production simulation cases. Two of the five cases had different 

assumptions for coal plant commitment, forced outage modeling, coal unit retirements, and 

modeling of the Missouri River hydro plants. The modeling assumptions for each case are 

summarized in Table 7-2. Scenario 1a is a sensitivity case with respect to Scenario 1. That is, 

Scenarios 1 and 1a have the same renewable energy penetration, but with different system 

operating assumptions. Similarly, Scenario 2a is a sensitivity case with respect to Scenario 2. Thus, 

the original three scenarios expanded to five scenarios for this aspect of the technical analysis.

Table 7-1 Study Scenarios

Scenario Minnesota RE Penetration MISO Wind & Solar Penetration (including MN)

Baseline 28.5% 14.0%

Scenario 1 40.0% 15.0%

Scenario 2 50.0% 25.0%

Note: MISO has an additional 3% renewable energy penetration in all scenarios from existing 

small biomass and small hydro.

Table 7-2 Major Assumptions for Production Simulation Analysis of Study Scenarios

Baseline Scenario 1 Scenario 1a Scenario 2 Scenario 2a

Coal plants modeling: Must-run (MR) 

or Security-Constrained Economic 

Commitment (SCEC)

MR MR SCEC MR SCEC

Forced outages included in 

generation modeling No No Yes No Yes

Nine Minnesota-Centric coal units 

retired Yes Yes No Yes No

Improved modeling of Missouri River 

hydro generation No No Yes Yes Yes

Minnesota load is served by a group of utilities and cooperatives with service territories that extend 

beyond the boundaries of the State of Minnesota. Therefore, the results of the production 

simulation analysis are summarized for the “Minnesota-Centric Region”, which consists of all 

generating resources operated by and system loads served by the Minnesota utilities. 
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OPERATIONAL PERFORMANCE RESULTS 7-2

Figure 7-1 shows a map of the Minnesota-Centric Region. The dots represent generating stations 

owned and operated by the Minnesota Utilities. The individual utilities are listed in the figure.

Figure 7-1 Minnesota-Centric footprint for production simulation (Plexos) Analysis

Dots indicate generating plants owned by Minnesota Utilities.

7.2 Annual Energy

Table 7-3 shows annual load, wind and solar energy for the Minnesota-Centric region for the study 

scenarios. The system load energy is, of course, the same for all scenarios. The bottom two rows 

show the MW rating of assumed wind and solar generation resources in the Minnesota-Centric 

region, which increase from the Baseline, to Scenarios 1/1a, and then further increase to the values 

in Scenarios 2/2a.

Note that the wind and solar energy penetration levels shown in this table are for the MinnesotaCentric Region and not specifically for the State of Minnesota. The amount of wind and solar 

generation resources included in the system models was calculated to meet the Minnesota RE 

penetrations specified in the study objectives (see Chapter 3). 
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OPERATIONAL PERFORMANCE RESULTS 7-3

In the production simulation analysis, the energy is summarized by “owner” (i.e., the utility which 

owns the bus where the generation is connected) consistent with the operation of the system. 

Therefore, the wind and solar energy penetration levels shown in the table are calculated for the 

entire Minnesota-Centric region, which includes all generating resources operated by and system 

loads served by the Minnesota utilities.

The results show that wind and solar curtailment is relatively small in all the scenarios. The levels of 

curtailment are considered to be within reason and not sufficient to be of concern. Experience from 

grid operations and from other renewable integration studies has shown that it is not economically 

justifiable to eliminate all causes of curtailment for all hours of the year. A small amount of 

curtailment is to be expected for any system.

Further analysis of wind and solar curtailment is presented in a subsequent section of this report.

Table 7-3 Annual Load, Wind and Solar Energy for Minnesota-Centric Region

Baseline Scenario 1 Scenario 1a Scenario 2 Scenario 2a

Load Energy (MWh) 147,807,020 147,807,020 147,807,020 147,807,020 147,807,020

Available Wind Energy (MWh) 37,286,193 45,753,928 45,753,928 61,789,277 61,789,277

Delivered Wind Energy (MWh) 37,129,632 45,298,460 45,025,066 60,467,557 60,799,826

Curtailed Wind Energy (MWh) 156,561 455,468 728,862 1,321,700 989,451

Curtailed Wind Energy 0.42% 1.00% 1.59% 2.14% 1.60%

Available Solar Energy (MWh) 702,562 2,002,969 2,002,969 6,870,164 6,870,164

Delivered Solar Energy (MWh) 701,936 2,002,869 1,998,268 6,841,300 6,853,503

Curtailed Solar Energy (MWh) 626 100 4701 28,864 16,661

Curtailed Solar Energy 0.09% 0.00% 0.23% 0.42% 0.24%

Wind Penetration 25.12% 30.65% 30.46% 40.91% 41.13%

Solar Penetration 0.48% 1.36% 1.35% 4.63% 4.64%

Wind+Solar Penetration 25.60% 32.00% 31.81% 45.54% 45.77%

MW Rating of Wind Fleet 11,039 12,970 12,970 18,140 18,140

MW Rating of Solar Fleet 470 1367 1367 4588 4588
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OPERATIONAL PERFORMANCE RESULTS 7-4

Figure 7-2 Annual generation in TWh by unit type for Minnesota-Centric region

Figure 7-2 shows the annual load and generation energy by type for the Minnesota-Centric region. 

Comparing Scenarios 1 and 1a (40% MN renewables) with the Baseline,

 Wind and solar energy increases by 8.5 TWh, all of which contributes to bringing Minnesota 

from 28.5% RE penetration to 40% RE penetration

 There is very little change in energy from conventional generation resources.

 Most of the increase in wind and solar energy is balanced by a decrease in imports

 The slight reduction in nuclear energy in Scenario 1a is due to forced outages.

Comparing Scenarios 2 and 2a (50% MN renewables) with Scenarios 1 and 1a (40% MN 

renewables),

 Wind and solar energy increases by 20 TWh. Of this total, 4.8 TWh brings Minnesota from 40% 

to 50% RE penetration and the remainder contributes to bringing MISO from 15% to 25% RE 

penetration

 Most of the increase in wind and solar energy in the Minnesota-Centric region is balanced by a 

decrease in coal generation and imports from neighboring regions
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OPERATIONAL PERFORMANCE RESULTS 7-5

 Gas-fired combined-cycle generation declines from 5.0 TWh in Scenario 1 to 3.0 TWh in 

Scenario 2

Figure 7-3 Annual Committed Capacity and Dispatch Energy 

for Coal and Combined-Cycle Units in the Minnesota-Centric Region

The left side of Figure 7-3 shows annual committed capacity and dispatched energy for coal units. 

In this figure, the total height of each bar indicates total annual coal unit committed capacity for the 

Minnesota-Centric Region. This is calculated by multiplying the hours online by the unit rating for 

each coal unit, and then totaling the values for all coal units. The light-blue segment of each bar is 

the energy dispatched (generated) from the coal units (i.e., the sum of energy output for all hours for 

all coal units). Comparing the Baseline with Scenarios 1 and 1a, there is no significant difference in 

coal unit commitment or dispatch. In Scenario 2, the dispatched energy from the coal units 

declines relative to the previous scenarios due to the increase in wind and solar generation. 

However, the coal fleet commitment remains nearly the same because many coal units in Scenario 

2 are assumed to be must-run and are not decommitted during periods of high wind and solar 

generation. In Scenario 2a, all coal units are economically committed/decommitted per market 

signals, so the overall commitment of the coal fleet is lower than in Scenario 2. Note that the coal 

fleet dispatch in Scenario 2a is higher than Scenario 2. This is because Scenario 2 assumes that 9 

coal units in the Minnesota-Centric region would be retired and Scenario 2a assumes that those 

units would be available to operate.
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OPERATIONAL PERFORMANCE RESULTS 7-6

The right side of Figure 7-3 shows similar information for the combined-cycle fleet. Comparing 

Scenarios 1 and 1a with Scenarios 2 and 2a, it is evident that utilization of the combined cycle fleet 

declines as wind and solar energy increases. 

The figure also indicates that CC fleet operation is more efficient in Scenario 1a (with coal units 

economically committed) than in Scenario 1 (with coal units assumed to be must-run). That is, the 

dispatched CC fleet energy output is a higher percentage of the CC fleet commitment. A similar 

observation can be made by comparing Scenario 2a with Scenario 2.

Figure 7-4 Annual Load and Net Load Duration Curves for Minnesota-Centric Region

The annual load and net load1 duration curves for the Minnesota-Centric region are shown in 

Figure 7-4 for the different scenarios. (Note, the net loads for scenarios 1a and 2a are essentially 

unchanged from scenarios 1 and 2 and are not shown here.) The areas between the curves 

represents the impact of the increasing renewable energy penetrations. The addition of over 

11,000 MW of renewable capacity from the Baseline Scenario to Scenario 2 reduced the peak net 

load by less than 800 MW while the minimum load was reduced by over 3,500 MW. The entire fleet 

of almost 23,000 MW of renewable capacity reduced the net peak load by about 3,000 MW while 

the minimum load was reduced by slightly more than 11,000 MW. 

 

1 Net load is calculated as hourly load energy minus wind and solar generation
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OPERATIONAL PERFORMANCE RESULTS 7-7

It is this fact that makes the cycling capability and minimum stable operating points of the 

conventional generation critical factors in the analysis.

The timing of the renewable energy is also reflected in Figure 7-5, which shows the annual duration 

curves of the net energy imports for the Minnesota-Centric region. The overall region is initially a 

net importer for the year but the increasing amounts of renewable energy shifts it to a net exporter. 

However, it can be seen that there is little change in the peak imports while the maximum exports 

increase from a little over 3,500 MW to 6,650 MW.

Figure 7-5 Annual Duration Curves of Energy Imports for Minnesota-Centric Region

7.2.1 Aggregate Wind and Solar Plant Capacity and Power Output

The dashed curves in Figure 7-6 show duration curves of the aggregate wind energy from all wind 

plants in the Minnesota-Centric region. Comparing the curves for the three scenarios shows the 

increase in wind energy from the Baseline to Scenario 1 to Scenario 2. The solid lines are duration 

curves of the aggregate ratings of the wind plants on-line. If a wind plant has no power output, 

then it is considered to be off-line with its power converters idle. If a wind plant is producing power, 

then it is considered to be on-line and all of its wind turbines and power converters are in-service 

and connected to the power grid. The flat shapes of these curves indicate that nearly all of the wind 

plants are on-line for nearly all hours of the year. The importance of this observation is discussed 

further in Section 7.7.1 (% non-synchronous generation and its impact on relative system strength).

Figure 7-7 is a similar plot for PV solar plants. The solid curves showing aggregate capacity on-line 

are essentially flat at full fleet rating for the daytime hours and flat at zero for nighttime hours.
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OPERATIONAL PERFORMANCE RESULTS 7-8

Figure 7-6 Duration Curves of Aggregate Wind Plant Capacity

On-Line and Aggregate Wind Plant Power Output for Minnesota-Centric Region

Figure 7-7 Duration Curves of Aggregate Solar Plant Capacity 

On-Line and Aggregate Solar Plant Power Output for Minnesota-Centric Region
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OPERATIONAL PERFORMANCE RESULTS 7-9

Comparisons of Generation Fleet Utilization for Study ScenariosTable 7-4 gives a more detailed 

breakdown of the commitment and dispatch by generation type for Scenarios 1 and 1a. As 

explained earlier, the “MWh Committed” reflects the entire rating of the plants whenever they are 

on line while the “MWh Dispatched” only reflects the actual energy output. The column “CF” is the 

capacity factor, which is the energy output divided by the capacity of the fleet times 8784 hours in 

the year. The next column, “Online CF”, is the average capacity factor over just those hours when 

the units are on. The clearest example of these terms is with the Combined Cycle units (CC). While 

the overall capacity factor only change slightly between the two scenarios, from 15% to 16%, the 

online CF, or average operating level, increased from 59% to 74% reflecting a much more efficient 

level of operation when the coal plants are permitted to cycle. Note, only units that operated at 

some time during the year were counted in the fleet, so the capacities could change slightly 

between scenarios.Table 7-5 shows a similar comparison for Scenarios 2 and 2a. Allowing the coal 

plants to cycle reduced their average capacity factors from 69% to only 58% but their average level 

of operation increased from 76% to 85%. The combined cycle units also increased the overall 

efficiency of their operation.
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OPERATIONAL PERFORMANCE RESULTS 7-10

Table 7-4 Comparison of Minnesota-Centric Generation Fleet Utilization

Scenarios 1 and 1a

S1 S1a

Δ (S1a-S1)

% Change 

in 

Unit Type Dispatch

Total MWh 

Committed

Total MWh 

Dispatched CF

Online 

CF

Total MWh 

Committed

Total MWh 

Dispatched CF

Online 

CF

Wind 113,516,032 45,298,460 40% 40% 112,894,006 45,025,066 40% 40% (273,394) -1%

ST Coal 76,285,799 69,984,409 65% 92% 75,904,870 70,043,841 65% 92% 59,432 0%

CT Gas 428,220 187,010 0% 44% 2,281,544 1,503,340 2% 66% 1,316,330 704%

CC 8,478,103 5,024,030 15% 59% 7,134,913 5,266,709 16% 74% 242,680 5%

Nuclear 20,209,392 20,036,836 96% 99% 19,414,416 19,246,693 93% 99% (790,143) -4%

Solar PV 5,175,211 2,002,869 15% 39% 5,164,167 1,998,268 15% 39% (4,600) 0%

Conventional 

Hydro 1,817,899 1,225,371 30% 67% 4,110,912 1,606,155 39% 39% 380,784 31%

ST Renewable 3,965,527 3,952,032 99% 100% 2,808,218 2,783,508 70% 99% (1,168,524) -30%

ST Gas 184,918 82,764 6% 45% 173,067 78,786 6% 46% (3,978) -5%

ST Other 641,604 635,462 92% 99% 614,174 607,706 88% 99% (27,756) 0%

IC Renewable 226,844 226,138 100% 100% 158,898 157,210 69% 99% (68,929) -31%

IC Gas 2,826 1,742 1% 62% 2,443 1,975 2% 81% 233 13%

Grand Total 230,932,414 148,657,123 - - 230,662,037 148,319,353 - - (337,770) 0%
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OPERATIONAL PERFORMANCE RESULTS 7-11

Table 7-5 Comparison of Minnesota-Centric Generation Fleet Utilization

Scenarios 2 and 2a

S2 S2a 

Δ (S2a-S2) 

% 

Change in 

Unit Type Dispatch 

Total MWh 

Committed 

Total MWh 

Dispatched CF 

Online 

CF 

Total MWh 

Committed 

Total MWh 

Dispatched CF 

Online 

CF 

Wind 157,339,652 60,467,557 38% 38% 157,943,346 60,799,827 38% 38% 332,270 1%

ST Coal 75,987,045 57,743,667 69% 76% 72,743,109 62,072,265 58% 85% 4,328,598 8%

CT Gas 388,393 175,805 0% 45% 1,241,682 867,191 1% 70% 691,387 393%

Solar PV 17,666,794 6,841,300 17% 39% 17,694,013 6,853,504 17% 39% 12,203 0%

CC 5,375,617 3,052,716 11% 57% 4,823,291 3,344,478 10% 69% 291,762 10%

Nuclear 20,207,026 20,036,836 96% 99% 19,414,416 19,246,693 93% 99% (790,143) -4%

Conventional 

Hydro 4,110,444 1,606,234 39% 39% 4,110,912 1,606,218 39% 39% (16) 0%

ST Renewable 3,974,220 3,715,592 93% 93% 2,808,218 2,708,547 68% 96% (1,007,045) -27%

ST Gas 184,170 82,437 6% 45% 172,413 77,529 6% 45% (4,908) -6%

ST Other 641,526 632,029 92% 99% 614,174 606,931 88% 99% (25,098) -4%

IC Renewable 227,041 212,182 93% 93% 158,898 153,244 67% 96% (58,938) -28%

IC Gas 2,068 1,215 1% 59% 1,534 1,177 1% 77% (38) -3%

Grand Total 286,103,995 154,567,570 - - 281,727,049 158,338,290 - - 3,770,720 2%
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OPERATIONAL PERFORMANCE RESULTS 7-12

7.3 Wind and Solar Curtailment

Curtailment of wind or solar generation occurs when the system is not able to accommodate all of 

the wind and solar generation in a given hour. The two most common reasons for curtailment are:

 The available power at particular wind or solar plant (or group of plants) is higher than the 

capacity of transmission lines transmitting the power to the bulk grid. This is often referred to as 

“local congestion”. Given that the system operates with security-constrained economic 

dispatch, the limitation could reflect an N-1 and/or a prior outage condition.

 The aggregate wind and solar power generation over a wide area exceeds what the grid can 

accommodate, even after all committed conventional power plants are dispatched at their 

minimum power levels and regional exports are maximized. This is sometimes referred to as a 

“minimum generation” condition.

In general, a small amount of curtailment is to be expected in any system with a significant level of 

wind and solar generation. There will be occasional operating conditions where it is economically 

efficient to accept a small amount of curtailment (i.e., where mitigation of that curtailment would be 

disproportionately expensive and not justifiable).

Table 7-6 shows annual curtailment of wind and solar energy as a percentage of the total available 

wind and solar energy. In all scenarios the level of curtailment in the Minnesota-Centric region is 

relatively small. Figure 7-8 shows annual duration curves of hourly solar curtailment. An inset in 

the figure shows an expanded view of the hours with the most curtailment. Curtailment occurs for 

only a very few hours of the year. Scenario 2 has the most curtailment of solar energy; more than

800 MW is curtailed during the worst hour. Further investigation of curtailment by plant revealed 

that the majority of all solar energy curtailment in Scenario 2 occurred in only two specific plants, 

indicating that it is likely caused by local congestion. Nonetheless, only 3% of total available solar 

energy is curtailed in these plants.

Figure 7-9 shows annual duration curves of hourly wind curtailment. In the Baseline and Scenario 

1, there are a few hours where wind curtailment approaches 1000 MW. But for the rest of the year, 

curtailment is very low. In Scenario 2, there are several hours where wind curtailment exceeds 

3000 MW. Figure 7-10 shows total curtailed wind energy by hour of day. In all scenarios, there is 

higher curtailment in nighttime hours (when many baseload generators are dispatched to their 

minimum output levels) than in daytime or evening hours. The trend most prominent in Scenario 2. 

This suggests that a portion of the overall curtailment is likely due to system-wide minimum 

generation conditions. This type of curtailment could be reduced by decommitting some baseload 

generation via economic market signals. The effectiveness of this mitigation option is illustrated by 

comparing Scenario 2 (coal units must-run) with Scenario 2a (economic coal commitment). Wind 

curtailment decreases from 2.14% to 1.60% (a reduction of 332 GWh). 

Figure 7-10 also illustrates that there is some wind curtailment during daytime and evening hours, 

when conventional generation could likely be dispatched down if needed. This suggests that a 

portion of the wind curtailment is due to local transmission congestion at wind plants. In fact, 

further investigation revealed that the majority of wind curtailment in the Baseline and Scenario 1 

occurred in just a few wind plants. This cause for curtailment could be mitigated by transmission 

modifications, if economically justifiable. 
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OPERATIONAL PERFORMANCE RESULTS 7-13

Table 7-6 Annual Wind and Solar Energy Curtailment

Baseline Scenario 1 Scenario 1a Scenario 2 Scenario 2a

Wind Curtailment 0.42% 1.00% 1.59% 2.14% 1.60%

Solar Curtailment 0.09% 0.00% 0.23% 0.42% 0.24%

Figure 7-8 Annual Duration Curves of Solar Curtailment for Minnesota-Centric Region
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OPERATIONAL PERFORMANCE RESULTS 7-14

Figure 7-9 Annual Duration Curves of Wind Curtailment for Minnesota-Centric Region

Figure 7-10 Wind Curtailment by Hour of Day for Minnesota-Centric Region
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OPERATIONAL PERFORMANCE RESULTS 7-15

7.4 Thermal Plant Cycling

7.4.1 Coal Units

Shutting down and then restarting generating units is called “cycling”. Increased cycling of 

conventional generation is a natural side effect of increased wind and solar generation. Some 

conventional generators are shut down during periods of high wind and solar energy production, 

and then restarted afterwards. 

Some types of units are designed to withstand multiple shutdown/startup cycles (eg., combustion 

turbines, hydro generators, combined cycle units). However, most coal plants were originally 

designed for baseload operation; that is, they were intended to operate continuously with only a 

few start/stop cycles in a year (mostly due to scheduled or forced outages). Increased cycling duty 

could impact wear and tear on these units, with corresponding impacts on maintenance 

requirements. 

Many coal plants in MISO presently are designated by the plant’s owner to operate as “must-run” to 

avoid start/stop cycles that would occur if they were economically committed by the market. 

Figure 7-11 through Figure 7-15 illustrate the amount of cycling for coal plants in the MinnesotaCentric region.

 Figure 7-11 shows total annual starts plotted as a function of unit rating for Baseline, Scenario 1 

and Scenario 2. In these scenarios, all but three coal units were assumed to be must-run, 

consistent with existing operating practices for those units. Hence, those units show only one 

start per year, following a scheduled maintenance period. The three economically committed 

coal units experienced from 50 to 230 starts per year.

 Figure 7-12 shows total annual starts for Scenarios 1 (with must-run assumption) and Scenario 

1a (with economic commitment and forced outages). In Scenario 1a, coal units experience 

significantly more cycling duty than in Scenario 1. The plot also shows a general trend where 

smaller coal units have more annual starts than larger units.

 Figure 7-13 shows a similar comparison for Scenarios 2 and 2a. The trends are similar to the 

pervious figure.

 Figure 7-14 shows a comparison of total annual starts for Scenarios 1a and 2a. In both 

scenarios, the coal unit modeling assumptions are the same (economic commitment, forced 

outages). The only difference is that Scenario 2a has higher wind and solar penetration than 

Scenario 1a. The plot shows that nearly all coal units experience higher cycling duty when the 

penetration of wind and solar energy increases.

 The previous figures showed total annual starts due to scheduled outages, forced outages, and 

economic commitment. Figure 7-15 shows only “operational” starts due to economic 

commitment. This figure enables a direct comparison of how increased wind and solar 

penetration affects the cycling duty if the coal units are economically committed by the energy 

market. Cycling duty increases significantly on nearly all coal units.
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OPERATIONAL PERFORMANCE RESULTS 7-16

Note on Coal Plant Modeling: In this study, coal plants were modeled using data that was derived 

from the publically available Ventyx dataset, and further vetted by MISO for use in their production 

simulation analysis studies. Data affecting plant cycling (minimum down time, startup time, startup 

cost, etc) are representative values for the types of plants modeled. A more thorough analysis of 

coal plant cycling performance would require use of proprietary plant specific data for individual 

coal units, which was beyond the scope of this study.

Figure 7-11 Coal Unit Total Annual Starts for Baseline, Scenario 1 and Scenario 2
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OPERATIONAL PERFORMANCE RESULTS 7-17

Figure 7-12 Coal Unit Total Annual Starts for Scenario 1 and Scenario 1a

Figure 7-13 Coal Unit Total Annual Starts for Scenario 2 and Scenario 2a
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OPERATIONAL PERFORMANCE RESULTS 7-18

Figure 7-14 Coal Unit Total Annual Starts for Scenario 1a and Scenario 2a

Figure 7-15 Coal Unit Annual “Operational” Starts due to Economic Commitment 

for Scenario 1a and Scenario 2a
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OPERATIONAL PERFORMANCE RESULTS 7-19

7.4.2 Combined-Cycle Units

Combined-cycle (CC) units are better able to accommodate cycling duties than coal plants. 

Figure 7-16 is a plot of annual CC unit starts for all 5 scenarios. The data shows that some CC units 

in the Minnesota-Centric region experience as many as 200 start/stop cycles per year, while other 

units experience only a few cycles per year. In general, cycling of CC units declines slightly as wind 

and solar penetration increases. This decline is primarily due to a decrease in CC plant utilization as 

wind and solar energy increases.

Figure 7-16 Combined-Cycle Unit Total Annual Starts

for Baseline, Scenario 1, Scenario 1a, Scenario 2 and Scenario 2a

7.5 MISO Ramp-Range and Ramp-Rate Capability

Ramp-range and ramp-rate capabilities of a balancing area’s conventional generation fleet are 

measures of its ability to accommodate the variability and uncertainty associated with wind and 

solar generation (i.e., the fleet’s ability to follow changes in wind plant output or to compensate for 

forecast errors in system load and wind/solar energy production. This analysis was conducted for 

all of MISO Central-North, since this capability is only relevant for a balancing area. 

Figure 7-17 shows range-up capability for the MISO conventional generation fleet for the Baseline, 

Scenario 1 and Scenario 2. Figure 7-18 shows ramp-rate up capability for the same scenarios. 

Ramp-range-up and ramp-rate-up capability of the MISO conventional generation fleet increases 

with increased penetration of wind and solar generation. Conventional generation is generally 

dispatched down rather than decommitted when wind and solar energy is available, which gives 

those generators more headroom for ramping up if needed.
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OPERATIONAL PERFORMANCE RESULTS 7-20

Figure 7-19 shows range-down capability for the MISO conventional generation fleet for the 

Baseline, Scenario 1 and Scenario 2. Figure 7-20 shows ramp-rate down capability for the same 

scenarios. Ramp-range-down and ramp-rate-down capability of the MISO conventional generation 

fleet decreases with increased penetration of wind and solar generation. In Scenario 2, there are 

500 hours when ramp-rate-down capability of the conventional generation fleet falls below 100 

MW/min. As shown in Figure 7-21, periods of low ramp-down capability coincide with periods of 

high wind and solar generation (see regions within red boxes). Wind and solar generators are 

capable of providing additional ramp-down capability to MISO during these periods. MISO’s existing 

Dispatchable Intermittent Resource (DIR) process already enables this for wind generators. It is

anticipated that MISO would expand the DIR program to include solar plants in the future.

Figure 7-17 Annual Duration Curve of Range-Up Capability 

for Conventional Generation within MISO Central-North

Figure 7-18 Annual Duration Curve of Ramp-Rate-Up Capability 

for Conventional Generation within MISO Central-North
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OPERATIONAL PERFORMANCE RESULTS 7-21

Figure 7-19 Annual Duration Curve of Range-Down Capability 

for Conventional Generation within MISO Central-North

Figure 7-20 Annual Duration Curve of Ramp-Rate-Down Capability 

for Conventional Generation within MISO Central-North
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OPERATIONAL PERFORMANCE RESULTS 7-22

Figure 7-21 Scatter Plot of Ramp-Rate Down Capability 

of MISO Conventional Generation Fleet vs Wind Generation in Minnesota-Centric Region
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OPERATIONAL PERFORMANCE RESULTS 7-23

7.6 Carbon Emissions

Table 7-7 shows total annual carbon emissions for the study scenarios. Overall, the CO2 emissions 

are closely related to the amount of ST Coal committed in the system. Scenario 1a has nine more 

coal plants than Scenario 1. As a result, Scenario 1a has a higher level of CO2 emissions. Similarly, 

Scenario 2a has higher CO2 than Scenario 2 because of the nine additional coal plants.

Table 7-7 CO2 Emissions for the Minnesota-Centric Region

Baseline S1 S1a S2 S2a

Tons of CO2 83,627,254 82,055,702 84,027,816 67,882,045 73,991,430

Reduction Versus Baseline (Tons CO2) 1,571,551 (400,562) 15,745,209 9,635,823

7.7 Screening Metrics for Stability/Control Issues

The results of the production simulation analysis were screened to select challenging operating 

conditions for dynamic performance, and these operating points were subsequently analyzed with 

fault simulations in the dynamics task. This section describes the three screening metrics and the 

process for selecting specific system operating conditions for dynamic simulation analysis.

7.7.1 Percent Non-Synchronous Generation (% NS)

In order to assess the stability of the power system, focusing only on generation owned by the 

Minnesota utilities was no longer sufficient. To evaluate stability issues, it is necessary to consider all

generation located within the geographic area of interest. Thus, for this metric, the definition of the 

Minnesota-Centric region was modified to include all generation, regardless of owner or type, within 

the regions shown in Figure 7-22. The Minnesota-Centric region for calculating % non-synchronous 

(NS) is defined by the shaded area of the figure, and includes six sub-regions; Northern Minnesota, 

South and Central Minnesota, Southwest Minnesota, North Dakota, South Dakota and Iowa. Based 

on the physical location of the generation, the % NS metric was calculated for the MinnesotaCentric region and the six sub-regions.
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OPERATIONAL PERFORMANCE RESULTS 7-24

Figure 7-22 Geographic Footprint of Minnesota-Centric Region for % NS Metric

The % NS metric is the ratio of non-synchronous inverter-based generation (i.e. wind and solar) MW 

rating to the total generation (i.e. wind, solar and all conventional generation) MW rating within a 

given geographic boundary.

% NS =

Total online wind + solar MW rating

Total online generation MW rating

This metric is an indicator of ac system strength or weakness. Synchronous generators are pure 

voltage sources and therefore contribute short-circuit current and support the “strength” of the ac 

transmission system. Inverter-based generators do not contribute to system strength. Inverterbased generators depend on the system strength provided by synchronous machines (either 

generators or synchronous condensers) to operate in a stable manner. Low % NS indicates strong 

system conditions and high % NS indicates potentially weak system conditions. Hence, this metric 

can be used to identify periods of weak system conditions for further evaluation using dynamic 

analysis methods.

HVDC converters are also affected by system strength in a similar manner. HVDC converters have 

similar internal controls that can experience degraded stability under weak system conditions. 

However, given the scope of this study, the analysis reported here only considers weak system 

issues related to wind and solar generation.
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OPERATIONAL PERFORMANCE RESULTS 7-25

7.7.2 Percent Renewable Penetration (% RE)

The % RE metric is the ratio of all wind and solar generation MW output to the total MW output of all 

generation (including wind and solar) within a given geographic boundary:

% RE =

Wind + Solar MW dispatched

Total Generation MW dispatched

This metric was applied to the Minnesota-Centric region as defined in Figure 7-1. The % RE metric 

was selected as it is one of the traditional metrics used to identify periods of the year where there 

are high levels of renewable generation supplying the load in the system, and where the dynamic 

performance of the overall system is more dependent on the dynamic performance of the wind and 

solar resources. 

7.7.3 Transmission Interface Loading

This metric was used to identify periods of high loading on three interfaces that are important to the 

dynamic performance of the Minnesota region. High loading on these interfaces stresses the 

overall transmission system, and provides appropriate operating conditions for testing system 

resilience to transmission system faults.

North Dakota Export (NDEX): This interface consisted of 23 lines that provided most of the power 

transfer out of the North Dakota sub-region. The geographic representation of this interface is seen 

in Figure 7-23.

Figure 7-23 NDEX Transmission Interface
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OPERATIONAL PERFORMANCE RESULTS 7-26

Buffalo Ridge Outlet: This interface consisted of four selected transmission lines that transfer energy 

out of the wind rich Buffalo Ridge region. The physical location of the lines is seen in Figure 7-24.

Figure 7-24 Buffalo Ridge Outlet Lines
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OPERATIONAL PERFORMANCE RESULTS 7-27

Minnesota-Wisconsin Export (MWEX): This interface monitored the flows across three major 

transmission lines from Minnesota into Wisconsin(see Figure 7-25).

Figure 7-25 MWEX Transmission Interface

7.7.4 Analysis of Percent Non-Synchronous Generation

The % NS metric was calculated for each hour of the year and plotted as duration curves for the 

Minnesota-Centric region as well as its six subregions (per Figure 7-22). The results are plotted in 

Figure 7-26 through Figure 7-30. 

The % NS varies greatly across the five scenarios. The general trend is that % NS gradually 

increases from the Baseline (Figure 7-26) to Scenario 1 (Figure 7-27) and finally to Scenario 2 (Figure 

7-29). This correlates with the increased wind and solar generation displacing some of the 

conventional synchronous generation in the region. With lower levels of conventional plant online, 

the % NS values increase on average.
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OPERATIONAL PERFORMANCE RESULTS 7-28

Different trends are observed when comparing Scenario 1 with Scenario 1a (Figure 7-28). In 

Scenario 1a, there were nine additional coal plants (existing plants not retired), all of the coal plants 

were given more operational flexibility (i.e., not must-run), and the forced outage rates of the 

conventional plants were enforced. As a result, the tails of the duration curves show significant 

differences. The periods of higher % NS and lower % NS both increase. These same trends can be 

observed by comparing Scenario 2 with Scenario 2a in Figure 7-30. Table 7-8 provides the maxima 

and minima of % NS for each of the scenarios studied.

Figure 7-26 Baseline % NS Duration Curves

Figure 7-27 Scenario 1 % NS Duration Curves
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OPERATIONAL PERFORMANCE RESULTS 7-29

Figure 7-28 Scenario 1 (solid) and 1a (dashed) % NS Duration Curves

Figure 7-29 Scenario 2 % NS Duration Curves
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OPERATIONAL PERFORMANCE RESULTS 7-30

Figure 7-30 Scenario 2 (solid) and 2a (dashed) % NS Duration Curves

Table 7-8 Maximum and Minimum % NS Values

Scenario

Minnesota 

Centric

Northern 

Minnesota

South & 

Central 

Minnesota

Southwest 

Minnesota

North 

Dakota

South 

Dakota Iowa

Baseline

Max: 64%

Min: 42%

Max: 51%

Min: 22%

Max: 22%

Min: 6%

Max: 100%

Min: 95%

Max: 53%

Min: 34%

Max: 99%

Min: 67%

Max: 85%

Min: 53%

Scenario 1

Max: 67%

Min: 45%

Max: 53%

Min: 28%

Max: 34%

Min: 6%

Max: 100%

Min: 99%

Max: 56%

Min: 33%

Max: 95%

Min: 51%

Max: 85%

Min: 54%

Scenario 1a

Max: 70%

Min: 40%

Max: 56%

Min: 0%

Max: 38%

Min: 0%

Max: 100%

Min: 85%

Max: 70%

Min: 25%

Max: 93%

Min: 37%

Max: 90%

Min: 50%

Scenario 2

Max: 75%

Min: 52%

Max: 50%

Min: 0%

Max: 48%

Min: 0%

Max: 100%

Min: 99%

Max: 64%

Min: 14%

Max: 96%

Min: 47%

Max: 88%

Min: 62%

Scenario 2a

Max: 83%

Min: 52%

Max: 62%

Min: 0%

Max: 66%

Min: 9%

Max: 100%

Min: 90%

Max: 93%

Min: 25%

Max: 96%

Min: 45%

Max: 97%

Min: 44%
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OPERATIONAL PERFORMANCE RESULTS 7-31

7.7.5 Percent Renewable Penetration Analysis

Figure 7-31 shows duration curves of the % RE metric for the Minnesota Centric region for all five 

scenarios. The general trend from Baseline to Scenario 1 to Scenario 2 is an increase in the % RE 

penetration as the wind and solar levels increase and conventional generation is backed down to 

accommodate the increased output. 

Scenario 1a has a slightly higher % RE than Scenario 1, consistent with the change in % NS 

between the two scenarios. Conversely, Scenario 2a has a significantly lower % RE than Scenario 2. 

This is contrary to % NS which is higher for Scenario 2a than Scenario 2. This is primarily related to 

the changes in modeling assumptions for the coal units. In Scenario 2a where coal units are 

economically committed, fewer MW of ST Coal and CC generation are committed over the course of 

the year, but when a plant is committed it is run at a higher capacity factor. This behavior is 

documented in Section 7.4, where the transition from Scenario 2 to Scenario 2a, sees fewer TWh of 

ST Coal and CC generation being committed, but the dispatched TWh increasing.

Figure 7-31 % RE Penetration for the Minnesota-Centric Region
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OPERATIONAL PERFORMANCE RESULTS 7-32

7.7.6 Transmission Interface Loading

During periods of high transmission interface loading, the grid could be more vulnerable to power 

swings after transmission system faults.

In Figure 7-32 through Figure 7-34, the interface loading duration curves are compared for Scenario 

1 and Scenario 1a. These were the only two scenarios that were analyzed as they were the only 

ones that were studied for the dynamic analysis.

For each of the three interfaces an increase in interface loading is observed as the dispatch and 

commitment moves from Scenario 1 to Scenario 1a for the NDEX (Figure 7-32) and MWEX (Figure 

7-34) interfaces. This is due to the fact that there is an overall increase in the ST Coal in the subregions close to the interfaces. Both NDEX and MWEX see increases due to additional coal energy in 

North Dakota and Northern Minnesota from plants that were retired in Scenario 1 but were part of 

the ST Coal fleet in Scenario 1a. The Buffalo Ridge Outlet flow (Figure 7-33) is nearly the same in 

Scenarios 1 and 1a because these lines are primarily loaded with wind and solar power, which is 

nearly the same in both scenarios.

Figure 7-32 NDEX Total Loading for Scenario 1 and Scenario 1a
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OPERATIONAL PERFORMANCE RESULTS 7-33

Figure 7-33 Buffalo Ridge Outlet Loading for Scenario 1 and Scenario 1a

 

Figure 7-34 MWEX Total Loading for Scenario 1 and Scenario 1a
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OPERATIONAL PERFORMANCE RESULTS 7-34

7.8 Selection of Operating Conditions for Dynamic Analysis

Using the three metrics described in the previous section, seven stability cases were selected for 

each of the two studied scenarios, Scenario 1 and Scenario 1a, for a total of 14 cases. First they 

were screened based on the Scenario 1 data followed by a secondary screening and adjustment if 

necessary based on the Scenario 1a data.

This section describes the process of using the metrics to identify the stability cases. The goal of the 

screen process was to filter down the 8784 hours of operation from the production simulation 

results into small groups of hours with common operating conditions that would facilitate in 

building a commitment and dispatch in the appropriate power flow case. 

The first metric used to screen for stability cases was the % NS measure. The following process was 

used to identify appropriate cases to feed into the dynamic stability assessment.

1. The hourly % NS data for the scenario is plotted against the load duration curve for the 

Minnesota-Centric region. The load curve is segmented into 3 regions (peak, shoulder, light)

that correspond to the power flow cases (Figure 7-35). This provided system load levels that 

would serve as filters for the next step.

Figure 7-35 Load Duration Curve and % NS for the Minnesota-Centric Region 
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OPERATIONAL PERFORMANCE RESULTS 7-35

2. Next, the load and corresponding hourly % NS values were plotted chronologically (as in 

Figure 7-36). Once again, loading levels that corresponded to the power flow cases (peak, 

shoulder, light) were identified and used to refine the loading windows in hours with similar 

characteristics.

Figure 7-36 Chronological Load and % NS for the Minnesota-Centric Region
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OPERATIONAL PERFORMANCE RESULTS 7-36

3. To identify a group of hours with similar operating conditions, the data was filter by time of 

year (fall), system load level (shoulder) and highest % NS (>55%). The result was 118 hours 

that satisfied the criteria (Figure 7-37).

Figure 7-37 Filtered Load and % NS to the Fall Shoulder-Load Window

4. These 118 hours were then sorted by time of day to ensure that the hours with online solar 

(daytime hours) were captured and allowed for consistent hours in the commitment and 

dispatch (Figure 7-38). This resulted in 15 hours where the commitment and dispatch had 

very high % NS levels during a very small window.
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OPERATIONAL PERFORMANCE RESULTS 7-37

Figure 7-38 Further Filter Fall Shoulder Hours for Scenario 1 Stability Analysis
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OPERATIONAL PERFORMANCE RESULTS 7-38

Through this same methodology a further two stability cases were selected for the % NS case that 

corresponded to the peak load and light load periods and a high % RE case that corresponded to a 

light load period. Three additional cases were selected using the interface loading metric for a total 

of seven Scenario 1 stability cases (Table 7-9).

Table 7-9 Stability Cases for Scenario 1

Case Criteria Load

Day /

Night Notes

1 High % NS Shoulder Day 55% - 64% NS, 5 days in Nov., 

11am – 1pm

2 High % NS Light Night %NS > 60%, April 2-8, 

12am-7am

3 High % NS Peak Day 46% - 51% NS, July 21-27, 

2pm-7pm

4 High % RE Penetration Light Night %RE > 55%, Avg. 71% Oct. 1, 5-7, 

12am - 7am

5

High Transmission Loading 

NDEX Shoulder Night Path Loading>1900 MW, Oct. 25 – 30

6

High Transmission Loading 

Buffalo Ridge Outlet Shoulder Night Path Loading>2800 MW, May 20 – 22

7

High Transmission Loading 

MWEX Light Day Path Loading>1400 MW, June 8, 11, 14

Next, the seven cases were re-screened to ensure that the commitment and dispatch windows still 

corresponded to the limits of the defined stability metrics. For the interface loading metric, the three 

cases for Scenario 1, corresponded with the new data for Scenario 1a for the NDEX (Figure 7-39), 

Buffalo Ridge Outlet (Figure 7-40) and the MWEX (Figure 7-41) interfaces.

For the NDEX interface, the period highlighted in Figure 7-39, indicates an interface loading greater 

than 1900 MW. For the Buffalo Ridge Outlet interface, the highlighted period in Figure 7-40 indicates 

an interface loading greater than 2800 MW. Finally, for the MWEX interface, the highlighted period 

in Figure 7-41 indicates an interface loading greater than 1400 MW. These values are based on the 

highest observed flows on the interfaces and do not correlate with a particular stability limit for the 

system.
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OPERATIONAL PERFORMANCE RESULTS 7-39

Figure 7-39 NDEX Interface Screening for Scenario 1 and Scenario 1a

Figure 7-40 Buffalo Ridge Outlet Interface Screening for Scenario 1 and Scenario 1a
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OPERATIONAL PERFORMANCE RESULTS 7-40

Figure 7-41 MWEX Interface Screening for Scenario 1 and Scenario 1a

For the remaining four cases, Cases 1, 3 and 4 showed close correlation between Scenario 1 and 

Scenario 1a. As a result, the dispatches between these cases were compared and the power flow 

for the cases was adjusted according to the new Scenario 1a commitment and dispatch. Case 2 

was the only case that required an adjustment of the stability window. 

As seen in Figure 7-42, a new peak in % NS for the light load case was observed around hour 3000 

in Scenario 1a. As such, the methodology described previously in this section was applied and new 

commitment and dispatch for Case 2 was developed based on the Scenario 1a data. Overall, the 

new commitment and dispatch from Scenario 1a for Case 2 resulted in a net increase of 1288 MW 

of non-synchronous generation commitments. 

Figure 7-42 Case 2 Stability Screening for Scenario 1 and Scenario 1a
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DYNAMIC SIMULATION RESULTS 8-1

8 DYNAMIC SIMULATION RESULTS

The objective of this analysis was to tests the dynamic performance of the system under the most 

challenging system conditions observed in the scenario S1 and S1a production simulation analysis 

with respect to renewable generation. 

The dynamic study cases developed for the S1 analysis represent a full spectrum of operating 

conditions cover light load, shoulder load and peak load. Every wind plant was on line for each of 

the study cases. All PV plants and distributed PV were on line for daytime cases and off line for 

nighttime cases. Renewable generation levels were set based on the production simulation results 

for the condition being simulated.

The cases cover a wide range of synchronous generation commitment and dispatch due to the 

different screening metrics used to select challenging hours. In addition, two different production 

simulation runs were used (S1 and S1a), with their different assumptions on must-run status, 

generation retirement and forced outages. The study cases represent hours with lower than 

average commitment and dispatch of synchronous generation, giving a high percentage of 

renewable energy and non-synchronous generation on line. These cases also stress several critical 

interfaces and transfer paths with high Manitoba Hydro exports and high Buffalo Ridge Outlet, 

NDEX and MWEX interface flows.

8.1 Dynamic Performance Study Conditions

Power flow study cases were developed for the seven different system conditions described in the 

previous section. The commitment and dispatch of all generators (both conventional and 

renewable) throughout and outside of MISO was set based on unit operation during the 

corresponding hours in the production simulation analysis. Conventional units that were on line 

less than 25% of the sample hours were decommitted in the power flow case. Conventional units 

on line more than 25% of the sample hours were committed and operated at or above their 

average dispatch for those hours. Renewable generation was committed and dispatched based on 

the average of the sample hours from production simulation.

These dynamic study cases, listed in Table 8-1, include three light load, three shoulder load and one 

peak load condition Case 4 was used to test high MWEX transfers at light load. The table lists the 

case number from the production simulation analysis, the stability case name, the selection criteria, 

load level and comments. The notes include the percentage of non-synchronous generation (%NS) 

and percentage of renewable energy (%RE) for the Minnesota-centric region. These are calculates 

as:

%NS =

Total online wind + Solar MW rating

Total online generation MW rating

and 

%RE =

Wind + Solar MW dispatched

Total Generation MW dispatched
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DYNAMIC SIMULATION RESULTS 8-2

The notes also include information on high transmission loading where applicable. Note that 

analysis of high MWEX loading (case 7, light load) was performed using the light load case with high 

percentage of renewable energy (case 4), since this case has very high MWEX loading. Additional 

contingencies on the highest loaded MWEX lines were simulated to focus on the impact of high 

transfers.

Table 8-1 Stability Case Description

Case Name Criteria Load Notes

1 S1_SH_D01 High % NS Shoulder 49% NS Generation

37% Renewable Energy

2 S1_LL_D02 High % NS Light 48% NS Generation

36% Renewable Energy

3 S1_PK_D03 High % NS Peak 37% NS Generation

21% Renewable Energy

4 S1_LL_D04 High % RE 

Penetration Light 47% NS Generation40% Renewable Energy

5 S1_SH_D05 High Transmission 

Loading NDEX Shoulder

47% NS Generation

37% Renewable Energy

2334 MW NDEX Loading

6 S1_SH_D06

High Transmission 

Loading Buffalo 

Ridge Outlet

Shoulder

48% NS Generation

41% Renewable Energy

SW Minn Renewables at 95% Pmax

7 S1_LL_D04* High Transmission 

Loading MWEX Light

47% NS Generation

40% Renewable Energy

2424 MW MWEX Loading

* Note: Case 4 has MWEX loading above 1400 MW (max value from production simulation). The impact 

of MWEX loading was tested using this case, subject to additional contingencies on MWEX lines.

The MW dispatch of all Minnesota-centric generation is illustrated in Figure 8-1. This bar graph 

shows the total on-line generation in MW by type for each of the six study cases. Figure 8-2 shows 

the same information, but in the form of pie charts of the percentage of generation by type. This is 

similar to the percent renewable energy measure (%RE) used for the production simulation 

screening. The dispatches are shown in order of increasing generation, from light load to shoulder 

load to peak load. 

The reporting of %RE for the stability cases is lower than that reported in the production simulation 

analysis due to differences in the grouping of generation. However, the generation dispatch for 

each case matches the average dispatch for the selected time period in the production analysis.
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DYNAMIC SIMULATION RESULTS 8-3

Figure 8-3 shows the total MVA of committed Minnesota-centric generation by type for the six study 

cases. This measure sums the rated MVA of each on-line unit. It does not consider the MW output 

of the machine, only if the unit is on-line or not. Figure 8-4 presents the same information, but 

groups the generation as synchronous and inverter-based. The inverter-based generation us made 

up of all wind, solar PV and distributed PV since most of this generation is power electronic inverter 

based. Inverter-based generation is also referred to as non-synchronous. This figure shows the 

rated MVA of each type as a percentage of total on-line MVA. This measure is similar to the percent 

non-synchronous generation (%NS) used for production simulation screening. Note that HVDC 

converter stations are not included in the calculation of percent non-synchronous.

The measure of %NS for the light and shoulder load study cases is between 47% and 48% across 

the Minnesota-centric area. The measure of %NS for the peak load case is 37%. These measures 

are lower than the %NS reported in the production simulation analysis. This difference is due to 

three factors:

1. These calculations are based on the sum of rated MVA of on-line generators, where the 

production simulation analysis is based on the sum of rated MW. In general, a synchronous 

machine will have a higher MVA rating than a wind or PV plant with the same MW capability. 

This will lower the measure of percent non-synchronous. 

2. There are over 2700 MVA of synchronous units that were not included in the %NS 

calculations for production simulation, but are included in the calculations for stability 

analysis. This includes the two Quad Cities nuclear units (1068 MVA each). 

3. Over 4600 MW of the renewable generation added for Baseline and S1 scenarios was 

located at buses outside the Minnesota-centric footprint. These are modeled and included in 

the stability analysis but not accounted for in calculating the %NS measure.

While the calculation of %NS differs between the production simulation and stability cases, the 

actual commitment/dispatch in the stability simulations matches that of the production simulation.

Figure 8-5 shows the percentage of on-line synchronous and non-synchronous generation (based 

on rated MVA) for each of the six regions in the Minnesota-centric footprint for each study case. 

The same information is shown in Figure 8-6, but shown as total MVA. SW Minnesota is nearly 

100% non-synchronous generation for all of the dispatches. South Dakota averages over 60% NS, 

and is as high as 80% NS for the two light load cases. Iowa and North Dakoda have between 40% 

NS and 50% NS across the cases, and Northern, Central and South Minnesota have 20% or less 

%NS.

Figure 8-7 shows the dynamic reactive reserves from synchronous, non-synchronous and static var 

compensator SVC (labeled “Other”) sources for each region. The dynamic reactive reserves are 

calculated as the difference in the maximum reactive capability minus the reactive output of a unit. 

This calculation does not include mechanically switched capacitors. 

The dynamic reactive reserves closely follow the on-line MVA for each region. The renewable 

generation provides a significant portion of the dynamic reactive reserves in Iowa, North and South 

Dakota. All of the reactive reserves in SW Minnesota are from renewable generation sources. The 

±60 MVAr SVC at Lake Yankton was not included in this analysis.
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DYNAMIC SIMULATION RESULTS 8-4

The reactive reserves in Northern Minnesota are from synchronous generators and the Forbes SVC. 

The SVC is critical to supporting imports from Manitoba Hydro (MH). One objective in developing the 

power flow cases was to maintain over 350 MVAr of dynamic reserves from the SVC. This was 

achieved using the mechanically switched shunt capacitors associated with the SVC.

Figure 8-1 Minnesota Centric Dispatch (MW) By Unit Type
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Figure 8-2 Minnesota Centric Percentage Generation Dispatch by Type
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DYNAMIC SIMULATION RESULTS 8-6

Figure 8-3 Minnesota Centric Commitment (MVA) by Unit Type 

Figure 8-4 Percentage of On-line Non- vs Synchronous MVA 
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DYNAMIC SIMULATION RESULTS 8-7

Figure 8-5 Percentage of online, non- and synchronous MVA by Sub-Region
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DYNAMIC SIMULATION RESULTS 8-8

Figure 8-6 Online MVA of synchronous and non-synch Generation by Region

Figure 8-7 Dynamic Reactive Reserves of synchronous and non-synch Generation 

by Region
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DYNAMIC SIMULATION RESULTS 8-9

8.2 Voltage Regulation & Stability Analysis

8.2.1 Disturbances

This study considers a wide range of contingencies, listed in Table 8-2. The list of faults covers 

reference disturbances, disturbances in areas with low short circuit strength and faults along 

transmission interfaces. Faults 1 through 5 are established contingencies that test the traditional 

stability limitations of the system. Faults 6 through 10 (LSC1 through LSC5) and 16 were selected 

based on the weak system (low short circuit strength) analysis. These lines have the highest 

contribution to short circuit strength of the SW Minnesota region. Fault 11 tests the stability and 

voltage recovery of the Twin Cities area and Fault 12 tests a fault with generation tripping near SW 

Minnesota. Faults 13 through 16 were developed for high transmission loading cases (cases 5 

through 7) only. 

Table 8-2 Fault Description for Stability Analysis

No. Fault Name Description

1 EI2 CU HVDC Permanent Bipole fault with tripping of both Coal Creek units

2 AG1 SLG fault with breaker fail at Leland Olds on the Ft. Thompson 345 kV line

3 AG3 3 phase fault at Leland Olds on Ft. Thompson 345 kV line, Clear both ends of the line in 

4 cycles

4 NAD 4cycles 3 phase fault on the Dorsey to Forbes 500 kV line D602F at Forbes. Runback 

bi-poles that terminate at Dorsey

5 PCS SLG fault t with breaker fail at King with 8P6 stuck. Trips King-EauClaire-Arpin and 

King-Chisago 345 kV line

6 LSC1 3Φ Fault at Nobles on Lakefield Jct 345 kV line, clear both ends of the line in 4 cycles

7 LSC2 3Φ Fault at Fallow on Grimes 345 kV line, clear both ends of the line in 4 cycles

8 LSC3 3Φ Fault at Brookings Co. on Big Stone South 345 kV line, clear both ends of the line in 

4 cycles

9 LSC4 3Φ Fault at Split Rock on White 345 kV line, clear both ends of the line in 4 cycles

10 LSC5 3Φ Fault at Split Rock on Sioux City 345 kV line, clear both ends of the line in 4 cycles

11 Trip_DEERCK 3Φ Fault at Deer Creek 345 kV bus, clear fault in 4 cycles followed by tripping Deer 

Creek CC generator

12 Term_King 3Φ Fault at KOLMNLK3 on Terminal 345 kV line, clear both ends of the line in 4 cycles

13 AG1_v2 Single-line-to-ground fault with breaker fail at Leland Olds on the Groton 3 345 kV line

14 AG3_v2 Three-phase fault at Leland Olds on the Groton 3 345 kV line. Clear both ends of the 

line in 4 cycles

15 briggs Three-phase fault at Briggs on the NMA 345 kV line. Clear both ends of the line in 4 

cycles

16 sheas Three-phase fault at SHEAS LK3 on the HELENA 3 345 kV line. Clear both ends of the 

line in 4 cycles
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DYNAMIC SIMULATION RESULTS 8-10

8.2.2 Overall Results

Transient stability analysis evaluated system response to all fault listed in Table 8-2 . Faults 1 

through 12 were tested on all cases while faults 13 through 16 were tested on high transmission 

loading cases (cases 5 through 7) only.

All stability simulations were evaluated using the criteria describe in Section 5. This includes first 

swing and angular stability, possible system separation and cascading outage conditions based on 

operation of the system-wide generic impedance relay and post-fault voltage recovery. Transient 

response was considered stable if all units maintain stable response, voltage recovery meets testing 

criteria and there were no inadvertent impedance relay operations. The results of transient stability 

analysis are summarized in the Table 8-3. All tested scenarios produce transiently stable response 

with acceptable voltage recovery.

Table 8-3 Transient Stability Analysis Results

No Fault Name Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7

1 EI2 stable stable stable stable stable stable stable

2 AG1 stable stable stable stable stable stable stable

3 AG3 stable stable stable stable stable stable stable

4 NAD stable stable stable stable stable stable stable

5 PCS stable stable stable stable stable stable stable

6 LSC1 stable stable stable stable stable stable stable

7 LSC2 stable stable stable stable stable stable stable

8 LSC3 stable stable stable stable stable stable stable

9 LSC4 stable stable stable stable stable stable stable

10 LSC5 stable stable stable stable stable stable stable

11 Trip_DEERCK stable stable stable stable stable stable stable

12 Term_King stable stable stable stable stable stable stable

13 AG1_v2 NT NT NT NT stable NT NT

14 AG3_v2 NT NT NT NT stable NT NT

15 briggs NT NT NT NT NT NT stable

16 sheas NT NT NT NT NT stable NT

* NT is “Not Tested”

For transient stability analysis in this study new monitoring signals are introduced. These signals 

include dynamic monitoring of total active and reactive output of different types of generation (i.e. 

synchronous, wind, PV) and load for each of Minnesota footprint regions. The plots of selected 

traces of transient stability simulations are presented in the sections below. 
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Transient stability cases are grouped into three categories based on criteria used for their 

development. The categories are:

1. High percentage non-synchronous condition;

2. High percentage of renewable conditions

3. High transfer conditions, 

In the following section, the system response to selected faults is presented for each category of 

dispatch conditions.

8.2.3 High % NS conditions

The cases developed for high percentage of non-synchronous generation in Minnesota footprint 

are case 1, case 2 and case 3. The faults selected to represent system response on these cases are:

Case 1: Terminal King fault (3Φ Fault at KOLMNLK3 on Terminal 345 kV line, clear both ends of 

the line in 4 cycles)

Case 2: Trip DEERCK fault (3Φ Fault at Deer Creek 345 kV bus, clear fault in 4 cycles followed 

by tripping Deer Creek CC generator)

Case 3: AG3 fault (3 phase fault at Leland Olds on Ft. Thompson 345 kV line, Clear both ends of 

the line in 4 cycles)

This section lists plots of total Minnesota footprint as well as Minnesota-centric regions system 

generation and load response. The plots of system generation include active (left column) and 

reactive (right column) power of all synchronous generation, wind generation, PV plus DGPV and 

load. The plots show the total generation/load for the Minnesota-centric region and the six subregions. Also post fault voltage recovery of bus voltages close to a fault are presented.
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DYNAMIC SIMULATION RESULTS 8-12

Figure 8-8 Case 1: Terminal King Fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-13

Figure 8-9 Case 1: Terminal King fault Voltage Magnitude
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DYNAMIC SIMULATION RESULTS 8-14

Figure 8-10 Case 2: Trip DEERCK fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-15

Figure 8-11 Case 2: Trip DEERCK fault Voltage Magnitude
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Figure 8-12 Case 3: AG3 fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-17

Figure 8-13 Case 3: AG3 fault Voltage Magnitude
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DYNAMIC SIMULATION RESULTS 8-18

8.2.4 High %RE conditions

The case developed to reflect high percentage of renewable penetration in Minnesota footprint is 

case 4. This is a light load case representing dispatch in early October during night hours between 

12am and 7am. The fault selected is NAD fault (4cycles 3 phase fault on the Dorsey to Forbes 500 

kV line D602F at Forbes. Runback bi-poles that terminate at Dorsey). Minnesota footprint generation 

and load response to a NAD fault is presented in Figure 8-14. Voltage recovery at 500 kV buses

Figure 8-14 Case 4: NAD fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-19

Figure 8-15 Case 4: NAD fault Voltage Magnitude

8.2.5 High Transfer Conditions

The case developed to reflect high transmission loading on NDEX, Buffalo Ridge Outlet and MWEX 

interfaces are case 5, case 6 and case 7 respectively. The faults selected to represent system 

response on these cases are:

1. Case 5: AG1_v2 (Single-line-to-ground fault with breaker fail at Leland Olds on the Groton 3 

345 kV line)

2. Case 6: SHEAS (Three-phase fault at SHEAS LK3 on the HELENA 3 345 kV line. Clear both ends 

of the line in 4 cycles)

3. Case 7: BRIGS (Three-phase fault at Briggs on the NMA 345 kV line. Clear both ends of the 

line in 4 cycles)

Plots of Minnesota footprint area generation and load response as well as post fault voltage 

recovery is presented in Figure 8-16 through Figure 8-21.
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DYNAMIC SIMULATION RESULTS 8-20

Figure 8-16 Case 5: AG1_v2 fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-21

Figure 8-17 Case 5: AG1_v2 fault Voltage Magnitude
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DYNAMIC SIMULATION RESULTS 8-22

Figure 8-18 Case 6: SHEAS fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-23

Figure 8-19 Case 6: SHEAS fault Voltage Magnitude
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DYNAMIC SIMULATION RESULTS 8-24

Figure 8-20 Case 7: BRIGGS fault Active and Reactive Response
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DYNAMIC SIMULATION RESULTS 8-25

Figure 8-21 Case 7: BRIGGS fault Voltage Magnitude

8.3 Reactive Reserves

The dynamic reactive reserves for all test cases (plotted in Figure 8-7) were sufficient to maintain 

system stability and allow for acceptable voltage recovery. Both the transient voltage dip and posttransient voltages recovered met all screening criteria. 

Sensitivity analysis was performed on two areas to test the response with lower dynamic reactive 

reserves. The first sensitivity was performed on a localized load pocket. When developing the 

power flow cases, low voltage and power flow convergence issues were observed in the Tac Harbor

/ Silver Bay area of Northern Minnesota. This area has a significant amount of industrial load, 

including over 75 MW of large synchronous motor load. Some of the production simulation hours 

had all Silver Bay and Tac Harbor units turned off. In most cases, the power flow failed to converge 

with these units turned off. If the power flow did solve with the generators off, voltages were well 

below 1.0 pu. 

With all local generation off line, the Tac Harbor synchronous motors will be dynamically unstable 

for faults in the area. Turning on some units, either as generators or synchronous condensers will 

stabilized the motors. Though not tested, it is likely that new transmission and/or a static var 

compensator (SVC) would also stabilize the motors.
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DYNAMIC SIMULATION RESULTS 8-26

The second sensitivity was performed on the Manitoba Hydro (MH) HVDC ties and the 500 kV lines 

from MH to Minnesota. The 2028 power flow cases modeled a new HVDC tie into the Riel station 

along with reinforcements to the existing 500 kV system near the Iron Range. These reinforcements 

are intended to support higher MH exports. The HVDC inverter stations at Dorsey and Riel have 

several synchronous condensers to provide short circuit strength and reactive support. The 

S1_SH_D01 case has 2975 MW of MH exports. As noted above, all test disturbances are stable with 

acceptable post-fault voltage recovery for all of the test cases.

Several sensitivity simulations were performed on the shoulder load case (S1_SH_D01) with the Riel 

condensers turned off and the Dorsey condensers modeled with fixed field voltage. Modeling the 

Dorsey condensers with fixed field voltages allowed them to provide short circuit strength but not 

regulate voltages. Under these sensitivity test conditions, faults in Central Minnesota on the 

Terminal-King line caused a wide-spread instability. In order to stabilize this case, the MH exports 

had to be reduced by more than 500 MW. 

This sensitivity analysis showed that localized dynamic reactive power support is critical to 

maintaining system stability. The current plans, as modeled in this study, address this issue and are 

sufficient for the anticipated levels of MH exports. The current practice of operating the Silver Bay 

and/or Tac Harbor generators to support the local industrial load provides strong local area voltage. 

8.4 Weak Grid Analysis

As wind penetration increases and market commitment of synchronous resources decreases, there 

is a point where the grid is no longer strong enough (i.e. the impedance is too high) to support stable 

operation of the power electronic converters within the wind generators and PV plants. This can 

happen for single machines as well as for groups of machines in a wind plant and groups of wind 

plants in a region. 

This is an emerging issue. Very few systems have faced this issue in actual operation (e.g. a few 

events in Texas before the transmission system was reinforced). Very few transmission engineers 

understand this issue in depth, as it has its roots within the lowest-level internal controllers of the 

wind and solar power electronic converter equipment. Knowledge of this issue is built upon 

converter performance tests and detailed analysis using transient simulation tools such asPower 

Systems Computer Aided Design (PSCAD) and ElectroMagnetic Transients Program (EMTP). Since 

such tools and analytical methods are not well suited to studying large-scale risks for many plants 

over wide geographic areas, the challenge is to take what is learned from detailed analysis of a few 

plants and extend that learning across larger regions using more practical methods. 

8.4.1 Composite Short Circuit Ratio Concepts

Short Circuit Ratio (SCR) is a method used to screen for weak grid conditions near power electronic 

converters. This method has been used for decades to screen for weak grid conditions near HVDC 

converters and is currently being applied to wind plants. SCR is the ratio of the available system 

strength (measured in short circuit MVA) to the MW rating of the wind or PV plant. 

While SCR is well established and trusted for HVDC and single-plant wind projects, it is not well 

suited for areas with multiple wind and solar plants in close proximity. For such cases, the industry 

is moving towards the Composite Short Circuit Ratio (CSCR) of all plants together. 
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DYNAMIC SIMULATION RESULTS 8-27

Like SCR, this is the ratio of available short circuit MVA to plant MW rating. However, it accounts for 

multiple nearby plants by taking the ratio of composite short circuit MVA to that total MW rating of 

all plants. 

The composite short circuit MVA is calculated by tying together the buses at the low side of the 

interconnection transformers of all wind and/or PV plants, creating a “composite” bus. The short 

circuit MVA is then calculated at the composite bus through normal fault calculation methods. 

CSCR is the ratio of the composite short circuit MVA to the total MW rating of all the wind and PV 

plants. This is shown in Figure 8-22. The wind and PV plants are assumed to have no fault current 

contribution when calculating CSCR.

Figure 8-22 Example of composite, short-circuit MVA at Multiple Wind Plants

CSCR is calculated for normal and contingency conditions and considers generation off line. Unlike 

normal fault calculations, where the object is to determine the strongest system condition and 

highest fault current, CSCR calculations are intended to determine the weakest conditions the wind 

and PV will be expected to operate under. 

Based on current wind turbine generator technology, a system with a CSCR above about 2.5 to 3 is 

considered strong. The wind plants should not have control instability issues. CSCR below about 

1.7 to 1.5 is considered weak. CSCR below 1.0 would likely require mitigation, either at the plant 

through control tuning, by strengthening the system (e.g. new transmission or synchronous 

machines) or a combination of both. There is less experience with an acceptable CSCR level for PV 

plants.
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8.4.2 Identifying Weak Regions

One of the challenges in evaluating weak grid issues for this study was identifying regions of the 

Minnesota system and the groups of wind and PV plants within those regions that could have low 

CSCR. The approach used for this analysis was to find relatively weak regions where voltage 

regulation was impacted more by wind and PV than by synchronous generation.

A measure of voltage regulation ratio was developed as the ratio of Thevenin impedance looking 

into the terminals of all synchronous generation to the Thevenin impedance looking into the 

terminals of all wind and PV generation. The Thevenin impedance was calculated taking the MVA 

rating of each unit into account. A low Thevenin impedance indicates a bus with strong voltage 

regulation and a high impedance indicates less voltage regulation. Since the voltage regulation 

ratio was defined as synchronous to non-synchronous Thevenin impedance, a ratio greater than 

1.0 points to a bus with higher control from wind and PV than from synchronous generation. This 

corresponds to the regional measure of %NS, but on a substation level.

The voltage regulation ratio was calculated at all 230 kV and above Minnesota-centric buses. The 

total short circuit MVA was also calculated at the same buses. These two measures were then 

plotted for all buses and used to identify possible weak system areas with high renewables. This is 

shown in Figure 8-23. Each point in the plot represents a transmission bus, color coded by the six 

Minnesota-centric sub-regions. This plots is for n-0 transmission condition for the shoulder load 

case 1 dispatch (S1_SH_D01), as this cases had the overall highest percent non-synchronous 

generation.

Three clusters of buses are highlighted on the plot. Quad Cities 345 kV bus has 16,000MVA of short 

circuit strength and a voltage regulation ratio less than 0.5. This is to be expected, since both Quad 

Cities nuclear generating units are in service and dominate the voltage regulation at the 

transmission bus.

The Ashtabula plant in North Dakota is fed from Pillsbury 230 kV, near Fargo. This group of 230 kV 

buses, highlighted in the upper left corner of the plot, has a voltage regulation ratio above 3.0 and 

710 MVA of short circuit strength. This is clearly a system dominated by wind generation with little 

short circuit strength. The three Ashtabula wind sites have a total capacity of 377 MW. This gives a 

CSCR of 1.88 under n-0 transmission conditions (710MVA/377MW). This is in the range of concern, 

particularly since the CSCR would likely be lower with transmission outages. 

The transmission buses in SW Minnesota are shown with orange circles. Four 345 kV buses are 

highlighted; Obrien, Nobles, Huntley and Lakefield. These buses have a relatively high short circuit 

strength (5000 to 7000 MVA), but also have a high voltage regulation ratio (1.5 to 2.0). These buses 

are in the Buffalo Ridge area. The high voltage regulation ratio is due to the large amount of 

renewables in SW Minnesota (4344 MW total for S1). The short circuit strength is due to the strong 

345 kV transmission around the area, connecting it to synchronous generation to the west, south 

and east. System strength and CSCR calculations in this region are presented in the next section.

The analysis was also used to identify additional contingencies for the stability analysis. Critical 

transmission lines were identified based on initial loading (i.e. power flow in the base condition) and 

on the fault current contribution for faults on 345 kV buses around the Buffalo Ridge area. Tripping 

transmission lines that provide the highest fault current and have the highest initial loading will be 
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DYNAMIC SIMULATION RESULTS 8-29

most challenging from a weak-system and a transient disruption standpoint. Outages identified 

from the weak system analysis are identified as LSC1 through LSC5, and SHEAS in Table 8-2. 

Figure 8-23 SC MVA vs. Voltage Regulation Ratio 

for Minnesota-Centric Transmission Buses

8.4.3 Southwestern Minnesota CSCR

As discussed above, the SW Minnesota region has a high concentration of renewable generation 

and relatively high short circuit strength under normal operating conditions. In total, the region has 

4344 MW of renewable generation capacity for the S1 system. The rated MW of each plant in this 

area is listed in Table 8-4. New PV and New Wind represent renewable generation added for the 

baseline and S1 scenarios.

The CSCR for the composite of all of the SW Minnesota renewable generation was calculated by 

tying the low side of the interconnection transformers together with all renewable generation

disconnected. For the S1_SH_D01 case, the CSCR is 9040 MVA over 4344 MW, or 2.08. This is in the 

caution region.

The CSCR was calculated with generation throughout the Minnesota-centric region decommitted. 

In general, no single generator had a significant impact on CSCR. The greatest reduction was seen 

for decommitting both Prairie Island units (two 659 MVA nuclear units northeast of Buffalo Ridge). 
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DYNAMIC SIMULATION RESULTS 8-30

With both of these units off line, CSCR drops to from 2.08 to 2.00. Decommitting Neal 4 (711 MVA 

unit near Buffalo Ridge) reduced CSCR to 2.04.

Other decommitted units evaluated include Streeter, Ames, Coal Creek, Big Stone, Willmar, Heskett, 

JP Madgett, Stanton and King. These units were selected based on their commitment across all six 

stability cases and their operation in all of the selected hours. With all of these units off line, CSCR 

drops from 2.08 to 1.99. This is not a significant drop in CSCR, given the number of units 

decommitted. Sensitivity analysis was conducted where Hydro units at Garrison, Big Bend and 

Oahe were decommitted. These units had very little measurable impact on CSCR in the SW 

Minnesota region. 

Transmission outages play a larger role in CSCR than individual generator status. Loss of the Sheas 

Lake to Helena 345 kV lines decreases the CSCR from 2.08 to 1.90. All other transmission outages 

tested has much less impact on CSCR. For example, loss of the Nobles-Lakefield or White-Split Rock 

345 kV lines will only reduce the CSCR from 2.08 to 2.07. Several other transmission contingencies 

were studied but none had a significant impact on CSCR.

8.4.4 Mitigation through Wind/PV Inverter Controls

Standard inverter controls and setting procedures may not be sufficient for weak system 

applications. Loop gains of internal control functions inherently increase when system impedance 

increases, thereby reducing the stability margin of the controllers. Developers and equipment 

vendors must be made aware when new plants are being proposed for weak system regions so 

they can design/tune controls to address the issue. Wind plant vendors have made significant 

progress in designing wind and solar plant control systems that are compatible with weak system 

applications.

This approach becomes somewhat more difficult when there are wind/solar plants from multiple 

vendors in one region. The level of analysis requires detailed modeling of all affected wind plants at 

a level of detail that requires the use of proprietary control design information from the vendors. 

Vendors are very reluctant to share such data, except with independent consultants who can 

guarantee strict data security. However, this approach is gaining traction and a few projects have 

made effective implementations. The key to success is that project developers and equipment 

vendors must be informed beforehand that a given wind or solar plant will be installed at a weak 

system location. This enables the appropriate control design studies to be initiated before the 

project is installed.

In the event that such control-based approaches are not sufficient, it would be possible to further 

improve weak system performance by employing one or more of the system-level mitigations 

discussed below.

8.4.5 Low CSCR Mitigation

Committing additional generation will increase CSCR, but the increase is not drastic unless large 

blocks of units are put on line. For example, committing all coal units rated above 50 MVA in the MN 

centric footprint (7160 MVA total) increases the CSCR from 2.08 to 2.18. This is a very modest 

increase for such a large amount of committed generation. Therefore, mitigating low CSCR issues 

through commitment of existing generation is not a reasonable solution. 
GE Energy Consulting MRITS Final Report

DYNAMIC SIMULATION RESULTS 8-31

Two more reasonable methods available to increase CSCR in SW Minnesota are: 

1. Add new synchronous machines, either generators or condensers, in the SW Minnesota 

region. 

2. Lower the impedance between the region and the surrounding synchronous generation 

through new transmission, new 345/115 kV transformers or lower impedance transformers 

at the renewable generation sites.

Analysis considered the impact of adding synchronous condensers at several 345 kV and 115 kV 

buses in the Buffalo Ridge region. 

Synchronous condensers are synchronous machines that have the same voltage control and 

dynamic reactive power capabilities as synchronous generators. Synchronous condensers are not 

connected to prime movers (e.g. steam turbines or combustion turbines), so they do not generate 

power.

Adding the condensers at the 115 kV level had the greatest increase in CSCR, since they were 

placed electrically closer to the renewable sites than on the higher voltage buses. For example, 

adding a 500 MVA of synchronous condensers at Lyon Co 115 kV and another 500 MVA at Nobles 

115 kV increased the CSCR to 2.4. Moving the condensers to the 345 kV buses had a much lower 

improvement in CSCR. 

Adding new transmission, particularly in the Sheas Lake area, will increase CSCR. Similarly, lower 

impedance transformers on the grid or in the renewable plants will increase CSCR. However, the 

benefits are likely to be modest. 
GE Energy Consulting MRITS Final Report

DYNAMIC SIMULATION RESULTS 8-32

Table 8-4 S1 Renewable Generation in SW Minnesota (Total MW Rating)
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-1

9 KEY FINDINGS

This study examined two levels of increased wind and solar generation for Minnesota; 40% 

(represented by Scenarios 1 and 1a) and 50% (represented by Scenarios 2 and 2a). In the 40% 

Minnesota Scenario, MISO North/Central is at 15% (current state RESs). The 50% Minnesota 

Scenario also included an increase of 10% (to 25%) in the MISO North/Central region. Production 

simulation was used to examine annual hourly operation of the MISO North/Central system for all

four of these scenarios. Transient and dynamic stability analysis was conducted for Scenarios 1 

and 1a but not on Scenarios 2 and 2a.

9.1 General Conclusions for 40% RE Penetration in Minnesota

With wind and solar resources increased to achieve 40% renewable energy for Minnesota and 15% 

renewable energy for MISO North/Central, production simulation and transient/dynamic stability 

analysis results indicate that the system can be successfully operated for all hours of the year with 

no unserved load, no reserve violations, and minimal curtailment of renewable energy. This 

assumes sufficient transmission mitigations, as described in Chapter 4, to accommodate the 

additional wind and solar resources.

This is operationally achievable with most coal plants operated as baseload must-run units, similar 

to existing operating practice. It is also achievable if all coal plants are economically committed per 

MISO market signals, but additional analysis would be required to better understand implications, 

tradeoffs, and mitigations related to increased cycling duty.

Dynamic simulation results indicate that there are no fundamental system-wide dynamic stability 

or voltage regulation issues introduced by the renewable generation assumed in Scenario 1 and 1a. 

This assumes:

 New wind turbine generators are a mixture of Type 3 and Type 4 turbines with standard controls

 The new wind and utility-scale solar generation is compliant with present minimum 

performance requirements (i.e. they provide voltage regulation/reactive support and have zerovoltage ride through capability)

 Local-area issues are addressed through normal generator interconnection requirements

9.2 General Conclusions for 50% RE Penetration in Minnesota

With wind and solar resources increased to achieve 50% renewable energy in Minnesota and 25% 

renewable energy in MISO, production simulation results indicate that the system can be 

successfully operated for all hours of the year with no unserved load, no reserve violations, and 

minimal curtailment of renewable energy. This assumes sufficient transmission upgrades, 

expansions and mitigations to accommodate the additional wind and solar resources.

This is operationally achievable with most coal plants operated as baseload must-run units, similar 

to existing operating practice. It is also achievable if all coal plants are economically committed per 

MISO market signals, but additional analysis would be required to better understand implications, 

tradeoffs, and mitigations related to increased cycling duty.
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-2

No dynamic analysis was performed for the study scenarios with 50% renewable energy for

Minnesota (Scenarios 2 and 2a) due to study schedule limitations and this analysis is necessary to 

ensure system reliability.

9.3 Annual Energy in the Minnesota-Centric Region

Figure 9-1 shows the annual load and generation energy by type for the Minnesota-Centric region. 

Comparing Scenarios 1 and 1a (40% MN renewables) with the Baseline,

 Wind and solar energy increases by 8.5 TWh, all of which contributes to bringing the State of

Minnesota from 28.5% RE penetration to 40% RE penetration

 There is very little change in energy from conventional generation resources

 Most of the increase in wind and solar energy is balanced by a decrease in imports. The 

Minnesota-Centric region goes from a net importer to a net exporter.

Comparing Scenarios 2 and 2a (50% MN renewables) with Scenarios 1 and 1a (40% MN 

renewables),

 Wind and solar energy increases by 20 TWh. Of this total, 4.8 TWh brings the State of Minnesota 

from 40% to 50% RE penetration and the remainder contributes to bringing MISO from 15% to 

25% RE penetration

 Most of the increase in wind and solar energy in the Minnesota-Centric region is balanced by a 

decrease in coal generation and an increase in net exports to neighboring regions

 Gas-fired, combined-cycle generation declines from 5.0 TWh in Scenario 1 to 3.0 TWh in 

Scenario 2.
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-3

Figure 9-1 Annual Energy by Type in Minnesota-Centric Region for Study Scenarios

9.4 Cycling of Thermal Plants

Most coal plants were originally designed for baseload operation; that is, they were intended to 

operate continuously with only a few start/stop cycles in a year (mostly due to scheduled or forced 

outages). Increased cycling duty could increase wear and tear on these units, with corresponding 

increases in maintenance requirements. Many coal plants in MISO presently are designated by the 

plant’s owner to operate as “must-run” in order to avoid start/stop cycles that would occur if they 

were economically committed by the market.

Scenarios S1a and S2a assumed that all coal plants in MISO are subject to economic 

commitment/dispatch (i.e., not must-run) based on day-ahead forecasts of load, wind and solar 

energy within MISO. Production simulation results show significant coal plant cycling due to 

economic market signals:

 Small coal units (below 300 MW rating) could have an additional 100 to 200 starts per year, 

beyond those due to forced or planned outages.

 Large coal units (above 300 MW) could have an additional 20 to 100 starts per year

Scenarios S1 and S2 assumed almost all coal plants would continue to operate as they do today. 

Coal units were on-line all year (except for scheduled maintenance periods) and were not 

decommitted during periods of low market prices. The results of these scenarios confirmed that the 

coal units could remain must-run with minor impacts on overall operation of the Minnesota-Centric 
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-4

region. Coal plant owners could choose to continue the must-run practice to avoid the detrimental 

impacts of increased cycling as wind and solar penetration increases. Doing so would likely incur 

some additional operational costs when energy prices fall below a plant’s breakeven point. Wind 

curtailment would also be about 0.5% higher than if the coal plants were economically committed.

An attractive solution to the coal plant cycling issue may exist between the two bookend cases 

analyzed in this study. Scenarios 1a and 2a assumed that unit commitment was determined on a 

day-ahead basis, using day-ahead forecasts of wind and solar energy. The result was a high 

number of start/stop cycles of coal plants, sometimes with down-times of less than 2 days. If the 

unit commitment process was modified to use a longer term forward market (say 3 to 5 days 

ahead), then coal plant owners could adjust their operational strategy to consider decommitting 

units when prolonged periods of high wind/solar generation and low system loads are forecasted. 

A forward market would depend on longer term forecasts of wind, solar and load energy, consistent 

with the look-ahead period of the market. Although such forecasts would be somewhat less 

accurate than day-ahead forecasts, the quality of the forecasts would likely be adequate to support 

such unit commitment decisions.

This study did not examine the economic or wear-and-tear impacts of increased cycling on coal 

units. Further information on this topic can be found in the NREL Western Wind and Solar 

Integration Study Phase 2 report1 and the PJM Renewable Integration Study report2. 

Combined-cycle (CC) units are better able to accommodate cycling duties than coal plants. 

Simulation results show that combined cycle units in the Minnesota-Centric region experience from 

50 to 200 start/stop cycles per year. Cycling of CC units declines slightly as wind and solar 

penetration increases. This decline is primarily due to a decrease in CC plant utilization as wind and 

solar energy increases.

9.5 Curtailment of Wind and Solar Energy

In general, a small amount of curtailment is to be expected in any system with a significant level of 

wind and solar generation. There are some operating conditions where it is economically efficient 

to accept a small amount of curtailment (i.e., mitigation of that curtailment would be 

disproportionately expensive and not justifiable).

Overall curtailment in the Minnesota-Centric region is relatively small in all study scenarios, as 

shown in Table 9-1. Wind curtailment in Baseline and Scenario 1 is primarily due to local

transmission congestion at a few wind plants. This congestion could be mitigated by transmission 

modifications, if economically justifiable. 

Wind curtailment in Scenario 2 is due to system-wide operational limits during nighttime hours, 

when many baseload generators are dispatched to their minimum output levels. This type of 

curtailment could be reduced by decommitting some baseload generation via economic market 

signals. The effectiveness of this mitigation option is illustrated by comparing Scenario 2 (coal units 

must-run) with Scenario 2a (economic coal commitment). Wind curtailment decreases from 2.14% 

to 1.60% (reduction of 332 GWh of wind curtailment). Solar curtailment decreases from 0.42% to 

0.24% (reduction of 12 GWh of solar curtailment).

 

1

http://www.nrel.gov/electricity/transmission/western_wind.html

2

http://www.pjm.com/committees-and-groups/task-forces/irtf/pris.aspx
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-5

Table 9-1 Wind and Solar Curtailment for Study Scenarios

Scenario Baseline Scenario 1 Scenario 1a Scenario 2 Scenario 2a

Wind Curtailment 0.42% 1.00% 1.59% 2.14% 1.60%

Solar Curtailment 0.09% 0.00% 0.23% 0.42% 0.24%

Note: Curtailment is calculated as a percentage of available annual wind or solar energy.

9.6 Other Operational Issues

No significant transmission system congestion was observed in any of the study scenarios with the 

assumed transmission upgrades and expansions. Transmission contingency conditions were 

considered in both the powerflow analysis used to develop the conceptual transmission system and 

the security-constrained economic dispatch in the production simulation analysis.

Ramp-range-up and ramp-rate-up capability of the MISO conventional generation fleet increases 

with increased penetration of wind and solar generation. Conventional generation is generally 

dispatched down rather than decommitted when wind and solar energy is available, which gives 

those generators more headroom for ramping up if needed.

Ramp-range-down and ramp-rate-down capability of the MISO conventional generation fleet 

decreases with increased penetration of wind and solar generation. In Scenario 2, there are 500 

hours when ramp-rate-down capability of the conventional generation fleet falls below 100 

MW/min. Periods of low ramp-down capability coincide with periods of high wind and solar 

generation. Wind and solar generators are capable of providing ramp-down capability during these 

periods. MISO’s existing Dispatchable Intermittent Resource (DIR) process already enables this for

wind generators. It is anticipated that MISO would expand the DIR program to include solar plants 

in the future.

9.7 System Stability, Voltage Support, Dynamic Reactive Reserves

No angular stability, oscillatory stability or wide-spread voltage recovery issues were observed over 

the range of tested study conditions. The 16 dynamic disturbances used in stability simulations 

included key traditional faults/outages as well as faults/outages in areas with high concentrations 

of renewables and high inter-area transmission flows. System operating conditions included light 

load, shoulder load and peak load cases, each with the highest percent renewable generation

periods in the Minnesota-Centric region.

Overall dynamic reactive reserves are sufficient and all disturbances examined for Scenarios 1 and 

1a show acceptable voltage recovery. The South/Central and Northern Minnesota regions get the 

majority of their dynamic reactive support from synchronous generation. Maintaining sufficient 

dynamic reserves in these regions is critical, both for local and system-wide stability. 

Southwest Minnesota, South Dakota and at times Iowa get a significant portion of dynamic reactive 

support from wind and solar resources. Wind and Solar resources contribute significantly to 

voltage support/dynamic reactive reserves. The fast response of wind/solar inverters helps voltage 

recovery following transmission system faults. However, these are current-source devices with little 

or no overload capability. Their reactive output decreases when they reach a limit (low voltage and 

high current). 
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-6

Synchronous machines (either generators or synchronous condensers), on the other hand, are 

voltage-source devices with high overload capability. This characteristic will strengthen the system 

voltage, allowing better utilization of the dynamic capability of renewable generation. The 

mitigation methods discussed below, namely stiffening the ac system through new transmission or 

synchronous machines, will also address this concern.

Local load areas, such as the Silver Bay and Taconite Harbor area, require reactive support from 

synchronous machines due to the high level of heavy industrial loads. If all existing synchronous 

generation in this region is off line (i.e. due to retirement or decommitment), reinforcements such as 

new transmission or synchronous condensers would be required to support the load.

Dynamic simulation results indicate that it is critical to maintain sufficient system strength and 

dynamic reserves to support high flows on the Northern Minnesota 500 kV lines and Manitoba highvoltage direct-current (HVDC) lines. Insufficient system strength and reactive support will limit 

Manitoba exports to the U.S. Existing transmission expansion plans, as modeled in this analysis,

address these issues and are sufficient for the anticipated levels of Manitoba exports.

The Manitoba HVDC ties and the 500 kV transmission system in Northern Minnesota require 

reactive support from synchronous generators, the Dorsey and Riel synchronous condensers, and 

the Forbes SVC to maintain the expected level of Manitoba exports. Without sufficient reactive 

reserves, the system could be unstable for nearby transmission disturbances. The current 

transmission plans, as modeled in this analysis, address this issue. 

9.8 Weak System Issues

Composite Short-Circuit Ratio (CSCR) is an indicator of the ability of an ac transmission system to

support stable operation of inverter-based generation. A system with a higher CSCR is considered 

strong and a system with a lower CSCR is considered to be weak. CSCR is calculated as the ratio of 

the composite short-circuit MVA at the points of interconnection (POI) of all wind/solar plants in a 

given area to the combined MW rating of all those wind and solar generation resources.

Low CSCR operating conditions can lead to control instabilities in inverter-based equipment (Wind, 

Solar PV, HVDC and SVC). Instabilities of this nature will generally manifest as growing 

voltage/current oscillations at the most affected wind or solar plants. In the worst conditions (i.e., 

very low CSCR), oscillations could become more wide-spread and eventually lead to loss of 

generation and/or damage to renewable generation equipment if not adequately protected against 

such events.

This is a relatively new area off concern within the industry. The issue has emerged as the 

penetration of wind generation has grown. Understanding of the fundamental stability issues is 

rapidly growing as more wind plants are being installed in regions with weak ac systems. 

Equipment vendors, transmission planners and consultants are all working to gain a better 

understanding of the issues. Modeling and simulation tools have already been developed to enable 

detailed analysis of the phenomena. Wind and solar inverter control systems are being modified to 

improve weak system performance.
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-7

Synchronous machines (either generators or synchronous condensers) contribute short-circuit 

strength to the transmission system and therefore increase CSCR. Therefore, system operating 

conditions with more synchronous generators online will have higher CSCR. Also, stronger 

transmission ties (additional transmission lines or transformers, or lower impedance transformers) 

between synchronous generation and regions of wind and solar generation will increase CSCR. 

SVCs and STATCOMs do not contribute short-circuit current, and because they are electronic

converter based devices with internal control systems similar to wind/solar inverters, their presence 

in a weak system region could further reduce the effective CSCR and exacerbate the control system 

stability issues that occur in weak system conditions.

There are two general situations where weak system issues generally need to be assessed:

 Local pockets of a few wind and solar plants in regions with limited transmission and no nearby 

synchronous generation (e.g. plants in North Dakota fed from Pillsbury 230 kV near Fargo).

 Larger areas such as Southwest Minnesota (Buffalo Ridge area) with a very high concentration 

of wind and solar plants and no nearby synchronous generation

This study examined the sensitivity of weak system issues in Southwest Minnesota. Observations 

are as follows:

The trouble spots identified in this analysis are not very sensitive to existing synchronous generation 

commitment. While there is very little synchronous generation within the area, the region is 

supported by a strong networked 345 kV transmission grid. Primary short circuit strength is from a 

wide range of base-load units in neighboring areas, and interconnected via the 345 kV transmission 

network. Commitment, decommittment or outages of individual synchronous generators do not 

have significant impact on CSCR in these identified areas.

Transmission outages will lower system strength and make the issue worse. When performing 

CSCR and weak system assessments as wind and solar penetration increases, it will be prudent to 

consider normal and design-criteria outages at a minimum (i.e, outage conditions consistent with 

MISO reliability assessment practices).

9.9 Mitigations

There are two approaches to improving wind/solar inverter control stability in weak system 

conditions:

 To improve the inverter controls, either by carefully tuning the equipment control functions or 

modifying the control functions to be more compatible with weak system conditions. With this 

approach, wind/solar plants can tolerate lower CSCR conditions.

 To strengthen the ac system, resulting in increased short-circuit MVA at the locations of the 

wind/solar plants. This approach increases CSCR.

The approaches are complementary, so the ultimate solution for a particular region would likely be 

a combination of both.
GE Energy Consulting MRITS Final Report

KEY FINDINGS 9-8

Mitigation through Wind/PV Inverter Controls

Standard inverter controls and setting procedures may not be sufficient for weak system 

applications. Loop gains of internal control functions inherently increase when system impedance 

increases, thereby reducing the stability margin of the controllers. Developers and equipment 

vendors must be made aware when new plants are being proposed for weak system regions so 

they can design/tune controls to address the issue. Wind plant vendors have made significant 

progress in designing wind and solar plant control systems that are compatible with weak system 

applications.

This approach becomes somewhat more difficult when there are wind/solar plants from multiple 

vendors in one region. The level of analysis requires detailed modeling of all affected wind plants at 

a level of detail that requires the use of proprietary control design information from the vendors. 

Vendors are very reluctant to share such data, except with independent consultants who can 

guarantee strict data security. However, this approach is gaining traction and a few projects have 

made effective implementations. The key to success is that project developers and equipment 

vendors must be informed beforehand that a given wind or solar plant will be installed at a weak 

system location. This enables the appropriate control design studies to be initiated before the 

project is installed.

In the event that such control-based approaches are not sufficient, it would be possible to further 

improve weak system performance by employing one or more of the system-level mitigations 

discussed below.

Mitigation by Strengthening the AC System

CSCR analysis of the Southwest Minnesota region shows that synchronous condensers located near 

the wind and solar plants would be a very effective mitigation for weak system issues. Synchronous 

condensers are synchronous machines that have the same voltage control and dynamic reactive 

power capabilities as synchronous generators. Synchronous condensers are not connected to 

prime movers (e.g. steam turbines or combustion turbines), so they do not generate power.

Other approaches that reduce ac system impedance could also offer some benefit:

 Additional transmission lines between the wind/solar plants and synchronous generation plants

 Lower impedance transformers, including wind/solar plant interconnection transformers

Series capacitors on transmission lines could be used to increase CSCR and to improve the 

transmission system’s capability to transfer energy out of regions with high concentrations of wind 

and solar resources. However, series capacitors create subsynchronous frequency resonances in 

the transmission system which affect the performance of control systems within wind and solar 

plants. These resonances introduce an additional challenge to wind/solar plant control designs, 

which must maintain stable operation in the presence of the resonant conditions.Mitigation through 

“must-run” operating rules for existing generation was found to be not very effective. The plants 

with synchronous generators are not located close enough to effected wind/solar plants.
GE Energy Consulting MRITS Final Report

REFERENCES 10-1

10 REFERENCES

1. NERC Integration of Variable Generation Task Force (IVGTF): “Special Assessment 2012 –

Requirements for Interconnection of Variable Generation”, September 2012. 

http://www.nerc.com/files/IVGTF_Task_1-3.pdf

2. NREL, “Western Wind and Solar Integration Study.” 

http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_final_report.pdf

3. NREL, “Western Wind and Solar Integration Study: Executive Summary.” 

http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_executive_summary.pdf

4. The Western Wind and Solar Integration Study Phase 2. 

www.nrel.gov/docs/fy12osti/56217.pdf<http://www.nrel.gov/docs/fy12osti/56217.pdf

5. New England ISO “New England Wind Integration Study.” http://www.isone.com/committees/comm_wkgrps/prtcpnts_comm/pac/reports/2010/newis_report.pdf

6. Ontario Power Authority, Independent Electricity System Operator, Canadian Wind Energy 

Association’s “Ontario Wind Integration Study.” 

http://www.powerauthority.on.ca/Storage/28/2321_OPA_Report_final.pdf

7. California Energy Commission’s Intermittency Analysis Project Study “Appendix B - Impact of 

Intermittent Generation on Operation of California Power Grid.” 

http://www.energy.ca.gov/2007publications/CEC-500-2007-081/CEC-500-2007-081-

APB.PDF

8. New York State Energy Research and Development Authority’s “The Effects of Integrating 

Wind Power on Transmission System Planning, Reliability, and Operations.” 

http://www.nyserda.org/publications/wind_integration_report.pdf

9. Hawaiian Electric Company, Hawaii Natural Energy Institute, “Oahu Wind Integration Study.” 

www.hnei.hawaii.edu
GE Energy Consulting MRITS Final Report

APPENDIX 11-1

11 APPENDICES

Appendix A1 – AC Input Files

Appendix A2 – Powerflow Case Flow Info

Appendix A3 – Bus Angle Diagrams

Appendix A4 – Contingency Analysis Spreadsheets

Appendix A5 – Maps

Appendix A6 – Transmission Costs

Appendix A7 – HVDC

Note: The Appendices are available upon request from Great River Energy.
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enveloped with postage paid in the United States Mail at St. Paul, Minnesota.

Minnesota Department of Commerce 

Report 

 

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										Minneapolis,										MN										55415-1842

Electronic Service 

Bill Heaney billheaney@billheaney.com IBEW Minnesota State

Council

940 44th Ave NE Unite21067										Columbia Hts,										MN										55421-3099

Electronic Service 

John Helmers helmers.john@co.olmsted.

mn.us

Olmsted County Waste toEnergy

2122 Campus Drive SE										Rochester,										MN										55904-4744

Electronic Service 

Jared Hendricks hendricksj@owatonnautiliti

es.com

Owatonna Public Utilities PO Box 800

										208 S Walnut Ave										Owatonna,										MN										55060-2940

Electronic Service 

Annete Henkel mui@mnutilityinvestors.org Minnesota Utility Investors 413 Wacouta Street

										#230										St.Paul,										MN										55101

Electronic Service 

Jessy Hennesy jessy.hennesy@avantener

gy.com

Avant Energy 220 S. Sixth St. Ste 1300

										Minneapolis,										Minnesota										55402

Electronic Service 
4

First Name Last Name Email Company Name Address Delivery Method S Mike Holly 4358@brainerd.net Sorgo Fuels and

Chemicals, Inc.

34332 Sunrise Blvd										Crosslake,										MN										56442

Electronic Service 

Ashley Houston 120 Fairway Rd

										Chestnut Hill,										MA										24671850

Paper Service 

Lori Hoyum lhoyum@mnpower.com Minnesota Power 30 West Superior Street

										Duluth,										MN										55802

Electronic Service 

Casey Jacobson cjacobson@bepc.com Basin Electric Power

Cooperative

1717 East InterstateAvenue										Bismarck,										ND										58501

Electronic Service 

Eric Jensen ejensen@iwla.org Izaak Walton League of

America

Suite 202										1619 Dayton Avenue										St. Paul,										MN										55104

Electronic Service 

Paula Johnson paulajohnson@alliantenerg

y.com

Alliant Energy-InterstatePower and Light Company

P.O. Box 351										200 First Street, SE										Cedar Rapids,										IA										524060351

Electronic Service 

Larry Johnston lw.johnston@smmpa.org SMMPA 500 1st Ave SW

										Rochester,										MN										55902-3303

Electronic Service 

Nate Jones njones@hcpd.com Heartland Consumers

Power

PO Box 248										Madison,										SD										57042

Electronic Service 

Julie Ketchum N/A Waste Management 20520 Keokuk Ave

										Lakeville,										MN										55044

Paper Service 

John Knofczynski Heartland Consumers

Power District

PO Box 248										203 W. Center Street										Madison,										SD										570420248

Paper Service 
5

First Name Last Name Email Company Name Address Delivery Method Renee Landwehr N/A Clean Power Markets, Inc. 303 Monroe St

										Little Chute,										WI										54140-1722

Paper Service 

Deborah Fohr Levchak dlevchak@bepc.com Basin Electric Power

Cooperative

1717 East InterstateAvenue										Bismarck,										ND										585030564

Electronic Service 

John Lindell agorud.ecf@ag.state.mn.us Office of the Attorney

General-RUD

1400 BRM Tower										445 Minnesota St										St. Paul,										MN										551012130

Electronic Service 

Mark Lindquist N/A The Minnesota Project 57107 422nd St

										New Ulm,										MN										56073-4321

Paper Service 

Dave McNary N/A Hennepin County DES 701 Fourth Avenue South

										suite 700										Minneapolis,										MN										55415-1842

Paper Service 

Stacy Miller stacy.miller@state.mn.us Department of Commerce State Energy Office

										85 7th Place East, Suite500										St. Paul,										MN										55101

Electronic Service 

David Moeller dmoeller@allete.com Minnesota Power 30 W Superior St

										Duluth,										MN										558022093

Electronic Service 

Andrew Moratzka apmoratzka@stoel.com Stoel Rives LLP 33 South Sixth Street

										Suite 4200										Minneapolis,										MN										55402

Electronic Service 

David W. Niles david.niles@avantenergy.c

om

Minnesota Municipal PowerAgency

Suite 300										200 South Sixth Street										Minneapolis,										MN										55402

Electronic Service 

Russell Olson N/A Heartland Consumers

Power District

PO Box 248										Madison,										SD										570420248

Paper Service 
6

First Name Last Name Email Company Name Address Delivery Method Thomas L. Osteraas bademail.tomosterass@ex

celsiorenergy.com

Excelsior Energy 150 South 5th Street Suite

2300										Minneapolis,										MN										55402

Paper Service 

Gerad Paul gpaul@minnkota.com Minnkota Power

Cooperative

1822 Mill Road										Grand Forks,										ND										58208-3200

Electronic Service 

Jan Pepper 418 Benvenue Ave.

										Los Altos,										CA										94024

Paper Service 

Mary Beth Peranteau mperanteau@wheelerlaw.c

om

Wheeler Van Sickle &Anderson SC

Suite 801										25 West Main Street										Madison,										WI										537033398

Electronic Service 

John C. Reinhardt Laura A. Reinhardt 3552 26Th Avenue South

										Minneapolis,										MN										55406

Paper Service 

Kevin Reuther kreuther@mncenter.org MN Center for

Environmental Advocacy

26 E Exchange St, Ste 206										St. Paul,										MN										551011667

Electronic Service 

Craig Rustad crustad@minnkota.com Minnkota Power 1822 Mill Road

										PO Box 13200										Grand Forks,										ND										582083200

Electronic Service 

Robert K. Sahr bsahr@eastriver.coop East River Electric Power

Cooperative

P.O. Box 227										Madison,										SD										57042

Electronic Service 

Raymond Sand rms@dairynet.com Dairyland Power

Cooperative

P.O. Box 8173200 EastAvenue South										LaCrosse,										WI										546020817

Electronic Service 
7

First Name Last Name Email Company Name Address Delivery Method Richard Savelkoul rsavelkoul@martinsquires.c

om

Martin & Squires, P.A. 332 Minnesota Street Ste

W2750										St. Paul,										MN										55101

Electronic Service 

Matthew J. Schuerger P.E. mjsreg@earthlink.net Energy Systems Consulting

Services, LLC

PO Box 16129										St. Paul,										MN										55116

Electronic Service 

Dean Sedgwick N/A Itasca Power Company PO Box 457

										Bigfork,										MN										56628-0457

Paper Service 

Mrg Simon mrgsimon@mrenergy.com Missouri River Energy

Services

3724 W. Avera Drive										P.O. Box 88920										Sioux Falls,										SD										571098920

Electronic Service 

Beth H. Soholt bsoholt@windonthewires.or

g

Wind on the Wires 570 Asbury Street Suite

201										St. Paul,										MN										55104

Electronic Service 

SaGonna Thompson Regulatory.Records@xcele

nergy.com

Xcel Energy 414 Nicollet Mall FL 7

										Minneapolis,										MN										554011993

Electronic Service 

Steve Thompson stevet@cmmpa.org Central Minnesota

Municipal Power Agency

459 S Grove St										Blue Earth,										MN										56013-2629

Electronic Service 

Pat Treseler pat.jcplaw@comcast.net Paulson Law Office LTD Suite 325

										7301 Ohms Lane										Edina,										MN										55439

Electronic Service 

Darryl Tveitbakk Northern Municipal Power

Agency

123 Second Street West										Thief River Falls,										MN										56701

Paper Service 
8

First Name Last Name Email Company Name Address Delivery Method Roger Warehime warehimer@owatonnautiliti

es.com

Owatonna Public Utilities 208 South WalnutPO Box

800										Owatonna,										MN										55060

Electronic Service 

Jason Weiers jweiers@otpco.com Otter Tail Power Company 215 South Cascade Street

										PO Box 496										Fergus Falls,										MN										56538

Electronic Service 

Paul White paul.white@prcwind.com Project Resources

Corp./Tamarac LineLLC/Ridgewind

618 2nd Ave SE										Minneapolis,										MN										55414

Electronic Service 

Robyn Woeste robynwoeste@alliantenerg

y.com

Interstate Power and LightCompany

200 First St SE										Cedar Rapids,										IA										52401

Electronic Service 

Thomas J. Zaremba TZaremba@wheelerlaw.co

m

WHEELER, VAN SICKLE& ANDERSON

Suite 801										25 West Main Street										Madison,										WI										537033398

Electronic Service