Generic Environmental

Impact Statement for

License Renewal of

Nuclear Plants

Supplement 39

Regarding 

Prairie Island Nuclear

Generating Plant, 

Units 1 and 2

Final Report 

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 39
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Generic Environmental 

Impact Statement for

License Renewal of

Nuclear Plants

Supplement 39

Regarding

Prairie Island Nuclear

Generating Plant,

Units 1 and 2

Final Report 

Manuscript Completed: May 2011 

Date Published: May 2011

Office of Nuclear Reactor Regulation 

NUREG-1437

Supplement 39

iii

ABSTRACT

This supplemental environmental impact statement has been prepared in response to an 

application submitted by Northern States Power Co. to renew the operating licenses for Prairie 

Island Nuclear Generating Plant, Units 1 and 2 for an additional 20 years. 

This supplemental environmental impact statement includes the preliminary analysis that 

evaluates the environmental impacts of the proposed action and alternatives to the proposed 

action. Alternatives considered include replacement power from a new natural-gas-firedcombined cycle plant; combination including natural gas, wind, wood-fired generation; 

combination including one PINGP 1 and 2 unit, natural gas, and wind; and not renewing the

licenses (the no-action alternative). 

The preliminary recommendation is that the Commission determine that the adverse 

environmental impacts of license renewal for Prairie Island Nuclear Generating Plant, Units 1 

and 2, are not so great that preserving the option of license renewal for energy-planning 

decision makers would be unreasonable.
iv
 v 

TABLE OF CONTENTS 

ABSTRACT .................................................................................................................................. iii 

TABLE OF CONTENTS ................................................................................................................ v

EXECUTIVE SUMMARY ............................................................................................................ xiii

ABBREVIATIONS AND ACRONYMS ........................................................................................ xix

1.0 PURPOSE AND NEED FOR ACTION ................................................................................. 1-1

1.1 Proposed Federal Action .................................................................................................. 1-1

1.2 Purpose and Need for the Proposed Federal Action ........................................................ 1-1

1.3 Major Environmental Review Milestones .......................................................................... 1-1

1.4 Generic Environmental Impact Statement ........................................................................ 1-3

1.5 Supplemental Environmental Impact Statement .............................................................. 1-5

1.6 Cooperating Agencies ...................................................................................................... 1-6

1.7 Consultations .................................................................................................................... 1-7

1.8 Correspondence ............................................................................................................... 1-7

1.9 Status of Compliance ..................................................................................................... 1-10

1.10 References ................................................................................................................... 1-12

2.0 AFFECTED ENVIRONMENT .............................................................................................. 2-1

2.1 Facility Description ........................................................................................................... 2-1

2.1.1 Reactor and Containment Systems ........................................................................... 2-1

2.1.2 Radioactive Waste Management ............................................................................... 2-2

2.1.2.1 Radioactive Liquid Waste .................................................................................... 2-3

2.1.2.2 Radioactive Gaseous Waste ............................................................................... 2-7

2.1.2.3 Solid Radioactive Waste ..................................................................................... 2-8

2.1.3 Nonradiological Wastes ............................................................................................. 2-8

2.1.3.1 Hazardous Waste ................................................................................................ 2-9

2.1.3.2 Universal Waste ................................................................................................ 2-10

2.1.3.3 Permitted Discharges ........................................................................................ 2-10

2.1.3.4 Pollution Prevention and Waste Minimization ................................................... 2-10

2.1.4 Plant Operation and Maintenance ........................................................................... 2-10

2.1.5 Power Transmission System ................................................................................... 2-11

2.1.6 Cooling and Auxiliary Water Systems ...................................................................... 2-15

2.1.6.1 Intake Screenhouse and Fish Return ................................................................ 2-16

2.1.6.2 Discharge and Cooling Tower System .............................................................. 2-18

2.1.6.3 Requirements Under NPDES Permit ................................................................ 2-18

2.1.7 Facility Water Use and Quality ................................................................................. 2-23

2.1.7.1 Ground Water Use ............................................................................................ 2-23

2.1.7.2 Surface Water Use ............................................................................................ 2-23

2.1.7.3 Surface Water Quality ....................................................................................... 2-24

2.1.7.4 Dredging ............................................................................................................ 2-24

2.2 Affected Environment ..................................................................................................... 2-24

2.2.1 Land Use .................................................................................................................. 2-24

2.2.2 Air and Meteorology ................................................................................................. 2-25

2.2.2.1 Climate and Meteorology .................................................................................. 2-25

2.2.2.2 Air Quality .......................................................................................................... 2-26
Table of Contents 

 vi 

2.2.3 Ground Water Resources ........................................................................................ 2-27

2.2.3.1 PINGP 1 and 2 Water Supply Wells .................................................................. 2-28

2.2.3.2 PINGP 1 and 2 Ground Water Monitoring ......................................................... 2-29

2.2.4 Surface Water Resources ........................................................................................ 2-29

2.2.5 Description of Aquatic Resources ............................................................................ 2-31

2.2.6 Terrestrial Resources ............................................................................................... 2-35

2.2.7 Threatened and Endangered Species ..................................................................... 2-37

2.2.7.1 Aquatic Species ................................................................................................ 2-37

2.2.7.2 Terrestrial Species ............................................................................................ 2-43

2.2.8 Socioeconomic Factors ............................................................................................ 2-47

2.2.8.1 Housing ............................................................................................................. 2-48

2.2.8.2 Public Services .................................................................................................. 2-49

2.2.8.3 Offsite Land Use ............................................................................................... 2-52

2.2.8.4 Visual Aesthetics and Noise .............................................................................. 2-57

2.2.8.5 Demography ...................................................................................................... 2-57

2.2.8.6 Economy ........................................................................................................... 2-64

2.2.9 Historic and Archaeological Resources ................................................................... 2-68

2.2.9.1 Cultural Background .......................................................................................... 2-68

2.2.9.2 Historic and Archaeological Resources ............................................................. 2-72

2.3 Related Federal and State Activities .............................................................................. 2-79

2.4 References ..................................................................................................................... 2-79

3.0 ENVIRONMENTAL IMPACTS OF REFURBISHMENT ....................................................... 3-1

3.1 Refurbishment Activities at PINGP 1 and 2 ...................................................................... 3-2

3.2 Environmental Impacts of Refurbishment ......................................................................... 3-3

3.2.1 Terrestrial Resources – Refurbishment Impacts ........................................................ 3-3

3.2.2 Threatened and Endangered Species ....................................................................... 3-4

3.2.2.1 Terrestrial Species .............................................................................................. 3-4

3.2.2.2 Aquatic Species .................................................................................................. 3-4

3.2.3 Air Quality During Refurbishment (Non-Attainment and Maintenance Areas) ........... 3-5

3.2.4 Housing Impacts ........................................................................................................ 3-6

3.2.5 Public Services – Education (Refurbishment) ............................................................ 3-7

3.2.6 Public Services – Public Utilities ................................................................................ 3-7

3.2.7 Public Services – Transportation ............................................................................... 3-7 

3.2.8 Offsite Land Use (Refurbishment) ............................................................................. 3-8 

3.2.9 Historic and Archaeological Resources ..................................................................... 3-8

3.2.10 Environmental Justice .............................................................................................. 3-9

3.3 Evaluation of New and Potentially Significant Information on 

Impacts of Refurbishment ......................................................................................... 3-10

3.4 Summary of Impacts of Refurbishment .......................................................................... 3-10

3.5 References ..................................................................................................................... 3-12

4.0 ENVIRONMENTAL IMPACTS OF OPERATION ................................................................. 4-1

4.1 Land Use .......................................................................................................................... 4-1

4.2 Air Quality ......................................................................................................................... 4-1

4.3 Ground Water ................................................................................................................... 4-2

4.3.1 Ground Water Use Conflicts (plants using >100 gpm)............................................... 4-2

4.3.2 Ground Water Use Conflicts (make-up from a small river) ........................................ 4-2

4.4 Surface Water .................................................................................................................. 4-3

4.4.1 Water Use Conflicts ................................................................................................... 4-4

4.5 Aquatic Resources ........................................................................................................... 4-5
Table of Contents

vii

4.5.1 Generic Aquatic Ecology Issues.............................................................................. 4-5

4.5.2 Entrainment and Impingement ................................................................................ 4-5

4.5.3 Heat Shock ........................................................................................................... 4-11

4.5.4 Total Impacts on Aquatic Resources ..................................................................... 4-13

4.6 Terrestrial Resources .................................................................................................. 4-13

4.7 Threatened or Endangered Species ............................................................................ 4-15

4.7.1 Aquatic Species .................................................................................................... 4-15

4.7.2 Terrestrial Species ................................................................................................ 4-21

4.8 Human Health.............................................................................................................. 4-21

4.8.1 Generic Human Health Issues............................................................................... 4-21

4.8.2 Microbiological Organisms – Public Health............................................................ 4-27

4.8.3 Electromagnetic Fields – Acute Shock .................................................................. 4-29

4.8.4 Electromagnetic Fields – Chronic Effects .............................................................. 4-30

4.9 Socioeconomics .......................................................................................................... 4-31

4.9.1 Generic Socioeconomic Issues ............................................................................. 4-31

4.9.2 Housing Impacts ................................................................................................... 4-31

4.9.3 Public Services: Public Utility Impacts ................................................................... 4-32

4.9.4 Offsite Land Use – License Renewal Period ......................................................... 4-33

4.9.5 Public Services: Transportation Impacts................................................................ 4-34

4.9.6 Historic and Archaeological Resources ................................................................. 4-35

4.9.7 Environmental Justice ........................................................................................... 4-41

4.10 Evaluation of New and Potentially Significant Information.......................................... 4-54

4.11 Cumulative Impacts ................................................................................................... 4-55

4.11.1 Cumulative Impacts on Aquatic and Water Resources ........................................ 4-56

4.11.2 Cumulative Impacts on Terrestrial Resources ..................................................... 4-58

4.11.3 Cumulative Human Health Impacts ..................................................................... 4-59

4.11.4 Cumulative Socioeconomic Impacts.................................................................... 4-60

4.11.5 Cumulative Environmental Justice Impacts ......................................................... 4-62

4.11.6 Summary of Cumulative Impacts......................................................................... 4-64

4.12 References ................................................................................................................ 4-65

5.0 ENVIRONMENTAL IMPACTS OF POSTULATED ACCIDENTS....................................... 5-1

5.1 Design Basis Accidents ................................................................................................. 5-1

5.2 Severe Accidents........................................................................................................... 5-2

5.3 Severe Accident Mitigation Alternatives ......................................................................... 5-3

5.3.1 Introduction ............................................................................................................. 5-3

5.3.2 Estimate of Risk ...................................................................................................... 5-4

5.3.3 Potential Plant Improvements.................................................................................. 5-5

5.3.4 Evaluation of Risk Reduction and Costs of Improvements....................................... 5-6

5.3.5 Cost-Benefit Comparison ........................................................................................ 5-6

5.3.6 Conclusions ............................................................................................................ 5-7

5.4 Environmental Justice Issues Related to Severe Accidents, as submitted by the PIIC... 5-7

5.5 References .................................................................................................................... 5-8

6.0 ENVIRONMENTAL IMPACTS OF THE URANIUM FUEL CYCLE AND 

SOLID WASTE MANAGEMENT............................................................................... 6-1

6.1 The Uranium Fuel Cycle ................................................................................................ 6-1

6.2 Greenhouse Gas Emissions .......................................................................................... 6-2

6.2.1 Introduction ............................................................................................................. 6-2

6.2.2 PINGP 1 and 2........................................................................................................ 6-3

6.2.3 GEIS ....................................................................................................................... 6-3
Table of Contents

viii

6.2.4 Other Studies .......................................................................................................... 6-3

6.2.5 Qualitative ............................................................................................................... 6-3

6.2.6 Quantitative............................................................................................................. 6-4

6.2.7 Summary of Nuclear Greenhouse Gas Emissions Compared to Coal ..................... 6-6

6.2.8 Summary of Nuclear Greenhouse Gas Emissions Compared to Natural Gas.......... 6-6

6.2.9 Summary of Nuclear Greenhouse Gas Emissions Compared to Renewable Energy 

Sources .............................................................................................................. 6-7

6.2.10 Conclusions........................................................................................................... 6-9

6.3 References .................................................................................................................. 6-10

7.0 ENVIRONMENTAL IMPACTS OF DECOMMISSIONING ................................................. 7-1

7.1 References .................................................................................................................... 7-1

8.0 ENVIRONMENTAL IMPACTS OF ALTERNATIVES ......................................................... 8-1

8.1 Gas-fired Generation ..................................................................................................... 8-3

8.1.1 Air Quality ............................................................................................................... 8-5

8.1.2 Ground Water Use and Quality ............................................................................... 8-7

8.1.3 Surface Water Use and Quality ............................................................................... 8-7

8.1.4 Aquatic and Terrestrial Ecology............................................................................... 8-7

8.1.5 Human Health ......................................................................................................... 8-8

8.1.6 Socioeconomics ...................................................................................................... 8-9

8.1.7 Waste Management .............................................................................................. 8-13

8.2 Combination Alternative 1............................................................................................ 8-13

8.2.1 Air Quality ............................................................................................................. 8-14

8.2.2 Ground Water Use and Quality ............................................................................. 8-16

8.2.3 Surface Water Use and Quality ............................................................................. 8-16

8.2.4 Aquatic and Terrestrial Ecology............................................................................. 8-16

8.2.5 Human Health ....................................................................................................... 8-17

8.2.6 Socioeconomics .................................................................................................... 8-18

8.2.7 Waste Management .............................................................................................. 8-23

8.3 Combination Alternative 2............................................................................................ 8-23

8.3.1 Air Quality ............................................................................................................. 8-24

8.3.2 Ground Water Use and Quality ............................................................................. 8-24

8.3.3 Surface Water Use and Quality ............................................................................. 8-24

8.3.4 Aquatic and Terrestrial Ecology............................................................................. 8-25

8.3.5 Human Health ....................................................................................................... 8-25

8.3.6 Socioeconomics .................................................................................................... 8-26

8.3.7 Waste Management .............................................................................................. 8-30

8.4 Purchased Power ........................................................................................................ 8-30

8.5 Alternatives Considered but Dismissed........................................................................ 8-31

8.5.1 Wind Power........................................................................................................... 8-31

8.5.2 Wood Waste.......................................................................................................... 8-31

8.5.3 Energy Conservation............................................................................................. 8-32

8.5.4 Solar Power .......................................................................................................... 8-32

8.5.5 Hydroelectric Power .............................................................................................. 8-33

8.5.6 Geothermal Power ................................................................................................ 8-33

8.5.7 Biofuels ................................................................................................................. 8-33

8.5.8 New Nuclear Power............................................................................................... 8-33

8.5.9 Coal-fired Power ................................................................................................... 8-33

8.5.10 Oil-fired Power .................................................................................................... 8-34

8.5.11 Fuel Cells ............................................................................................................ 8-34
Table of Contents

ix

8.5.12 Municipal Solid Waste ......................................................................................... 8-34

8.5.13 Delayed Retirement............................................................................................. 8-35

8.6 No-Action Alternative................................................................................................... 8-35

8.6.1 Air Quality ............................................................................................................. 8-36

8.6.2 Ground Water Use and Quality ............................................................................. 8-36

8.6.3 Surface Water Use and Quality ............................................................................. 8-36

8.6.4 Aquatic and Terrestrial Resources ........................................................................ 8-36

8.6.5 Human Health ....................................................................................................... 8-37

8.6.6 Socioeconomics .................................................................................................... 8-37

8.6.7 Waste Management .............................................................................................. 8-39

8.7 Alternatives Summary.................................................................................................. 8-39

8.8 References .................................................................................................................. 8-41

9.0 CONCLUSION.................................................................................................................. 9-1

9.1 Environmental Impacts of License Renewal .................................................................. 9-1

9.2 Comparison of Environmental Impacts of License Renewal and Alternatives ................ 9-2

9.3 Resource Commitments ................................................................................................ 9-2

9.3.1 Unavoidable Adverse Environmental Impacts ......................................................... 9-2

9.3.2 Relationship Between Local Short-Term Uses of the Environment and the 

Maintenance and Enhancement of Long-Term Productivity ................................ 9-3

9.3.3 Irreversible and Irretrievable Commitments of Resources ....................................... 9-3

9.4 Recommendations......................................................................................................... 9-4

10.0 LIST OF PREPARERS.................................................................................................. 10-1

APPENDIX A COMMENTS RECEIVED ON THE PRAIRIE ISLAND NUCLEAR 

GENERATING STATION, UNITS 1 AND 2, ENVIRONMENTAL REVIEW ...............A-1

APPENDIX B NEPA ISSUES FOR LICENSE RENEWAL OF 

NUCLEAR POWER PLANTS...................................................................................B-1

APPENDIX C APPLICABLE REGULATIONS, LAWS, AND AGREEMENT............................C-1

APPENDIX D CONSULTATION CORRESPONDENCE ........................................................D-1

APPENDIX E CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE.......E-1

APPENDIX F U.S NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

SEVERE ACCIDENT MITIGATION ALTERNATIVES (SAMAS) FOR PRAIRIE 

ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2, IN SUPPORT OF 

LICENSE RENEWAL APPLICATION REVIEW ........................................................ F-2

INDEX ...........................................................................................................................Index-1
Table of Contents

x

FIGURES

Figure 1-1. Environmental Review Process............................................................................. 1-2

Figure 1-2. Environmental Issues Evaluated During License Renewal.................................... 1-5

Figure 2-1. Location of Prairie Island Nuclear Generating Plant, Units 1 and 2, 50-mi (80-km) 

Region ................................................................................................................ 2-4

Figure 2-2. PINGP 1 and 2 General Site Layout and Exclusion Area Boundary ...................... 2-5

Figure 2-3. PINGP 1 and 2 Substation and Transmission Line Layout .................................. 2-13

Figure 2-4. PINGP 1 and 2 Transmission System................................................................. 2-14

Figure 2-5. Lithology and Generalized Geologic Section for the Prairie Island Low Island 

Terrace ............................................................................................................. 2-28

Figure 3-1. Potential Areas Impacted by Unit 2 Steam Generator Replacement ................... 3-11

Figure 4-1. Prairie Island Indian Community Trust Land Boundary........................................ 4-44

Figure 4-2. Minority Block Groups with a 50-mi (80 km) radius of PINGP 1 and 2................. 4-45

Figure 4-3. Low-income Block Groups with a 50-mi (80 km) radius of PINGP 1 and 2 .......... 4-46
Table of Contents

xi

TABLES

Table 1-1. Licenses and Permits. ......................................................................................... 1-11

Table 2-1. PINGP 1 and 2 Transmission Lines...................................................................... 2-15

Table 2-2. Post-modification Velocity Profiles for the PINGP 1 and 2 Cooling Water 

Intake System................................................................................................... 2-17

Table 2-3. PINGP 1 and 2 Screen Mesh Size and Spray Wash Pressure Requirements. ..... 2-19

Table 2-4. PINGP 1 and 2 Plant Flow (Discharge) Restrictions............................................. 2-19

Table 2-5. PINGP 1 and 2 Cooling Mode Requirements.. ..................................................... 2-20

Table 2-6. NPDES Effluent Limitations for PINGP 1 and 2.................................................... 2-21

Table 2-7. Surface Discharge (SD) and Internal Waste Stream (WS) Discharges from 

PINGP 1 and 2 (in millions of gallons per day [mgd]) ........................................ 2-22

Table 2-8. Total Annual Ground Water Withdrawal (Gallons) for PINGP 1 and 2. ................. 2-29

Table 2-9. Monthly Average Discharge Flow at Lock and Dam 3 from 1999 to 2006............. 2-31

Table 2-10. Total Yearly Discharge Flow at Lock and Dam 3 from 1999 to 2006 .................. 2-31

Table 2-11. Listed Aquatic Species....................................................................................... 2-41

Table 2-12. Listed Terrestrial Species................................................................................... 2-45

Table 2-13. PINGP 1 and 2 Employee Residence by County................................................ 2-48

Table 2-14. Housing in Goodhue County and Dakota Counties, Minnesota, 

and Pierce County, Wisconsin .......................................................................... 2-49

Table 2-15. Major Public Water Supply Systems (in million gallons per day [gpd])................ 2-51

Table 2-16. Major Commuting Routes in the Vicinity of the Prairie Island Nuclear 

Generating Plant and 2007 Average Annual Daily Traffic (AADT) Counts......... 2-53

Table 2-17. Population and Percent Growth in Goodhue County and 

Dakota County, Minnesota, and Pierce County, Wisconsin, 

from 1970 to 2000 and Projected for 2006 to 2050 ........................................... 2-58

Table 2-18. Demographic Profile of the Population in the PINGP 1 and 2 Three-County 

Socioeconomic Region of Influence in 2000 ..................................................... 2-59

Table 2-19. Demographic Profile of the Population in the PINGP 1 and 2 Three-County 

Socioeconomic Region of Influence in 2005-2007, 3-Year Estimate ................. 2-60

Table 2-20. Seasonal Housing in Counties Located within 50 mi (80 km) of 

PINGP 1 and 2.................................................................................................. 2-61

Table 2-21. Migrant Farm Worker and Temporary Farm Labor in Counties Located 

within 50 mi (80 km) of PINGP 1 and 2 ............................................................. 2-63

Table 2-22. Major Employers in Goodhue County................................................................. 2-64

Table 2-23. 2005-2007 Estimated Income for the PINGP 1 and 2 Region of Influence.......... 2-65

Table 2-24. PINGP 1 and 2 Property Tax Paid and Percentage of Goodhue County, 

City of Red Wing, and School District 256 Tax Revenues, 2001 to 2006 .......... 2-67

Table 2-25. Archaeological Sites within the PINGP 1 and 2 Site Boundary ........................... 2-74

Table 3-1. Issues Related to Refurbishment at PINGP 1 and 2............................................... 3-1

Table 4-1. Land Use Issues. ................................................................................................... 4-1

Table 4-2. Air Quality Issue..................................................................................................... 4-1

Table 4-3. Ground Water Use and Quality Issues.. ................................................................. 4-2

Table 4-4. Surface Water Quality Issues................................................................................. 4-3

Table 4-5. Aquatic Resources Issues...................................................................................... 4-5

Table 4-6. Estimated Number of Fish Impinged at PINGP 1 and 2, 1973-1984....................... 4-8

Table 4-7. Estimated Number and Percent Composition of Fish Life Stages 

Impinged on Fine Mesh Screens April through August, 1984-1988................... 4-10

Table 4-8. Upper Lethal Thresholds of Common Fish Species Occurring in the 

Vicinity of PINGP 1 and 2 ................................................................................. 4-12

Table 4-9. Terrestrial Resources Issues................................................................................ 4-13
Table of Contents

xii

Table 4-10. Threatened or Endangered Species................................................................... 4-15

Table 4-10 a. Estimated Impingement of Higgins eye Host Species, 1973 to 1984............... 4-17

Table 4-10 b. Mussel Species Age Class Distribution Along the Mississippi 

National River and Recreation Area Corridor, 2000-2001 ................................. 4-19

Table 4-10 c. Mussel Species Average, Minimum, and Maximum Ages within Pool 2 

of the Mississippi River, 2000-2001 .................................................................. 4-19

Table 4-11. Human Health Issues......................................................................................... 4-21

Table 4-12. Socioeconomic Issues........................................................................................ 4-31

Table 4-13. Summary of Cumulative Impacts on Resources Areas....................................... 4-65

Table 5-1. Issues Related to Postulated Accidents.. ............................................................... 5-1

Table 5-2. PINGP 1 and 2 Core Damage Frequency .............................................................. 5-4

Table 5-3. Breakdown of Population Dose by Containment Release Mode............................. 5-5

Table 6-1. Issues Related to the Uranium Fuel Cycle and Solid Waste Management.. ........... 6-2

Table 6-2. Nuclear Greenhouse Gas Emissions Compared to Coal........................................ 6-6

Table 6-3. Nuclear Greenhouse Gas Emissions Compared to Natural Gas ............................ 6-7

Table 6-4. Nuclear Greenhouse Gas Emissions Compared to Renewable Energy Sources.... 6-8

Table 7-1. Issues Related Decommissioning.. ........................................................................ 7-1

Table 8-1. Summary of Environmental Impacts of Gas-Fired Combined-Cycle Generation 

Compared to Continued PINGP 1 and 2 Operation............................................. 8-5

Table 8-2. Summary of Environmental Impacts of Combination Alternative 1 

Compared to Continued PINGP 1 and 2 Operation........................................... 8-14

Table 8-3. Summary of Environmental Impacts of Combination Alternative 2 

Compared to Continued PINGP 1 and 2 Operation........................................... 8-24

Table 8-4. Summary of Environmental Impacts of No Action Compared to 

Continued PINGP 1 and 2 Operation................................................................ 8-36

Table 8-5. Summary of Environmental Impacts of Proposed Action and Alternatives............ 8-40

Table 10-1. List of Preparers................................................................................................. 10-1
xiii

EXECUTIVE SUMMARY

Background

By letter dated April 11, 2008, Northern States Power Co. (NSP) [formerly Nuclear Management 

Company, LLC (NMC)] submitted an application to the U.S. Nuclear Regulatory Commission 

(NRC) to issue renewed operating licenses for the Prairie Island Nuclear Generating Plant, 

Units 1 and 2 (PINGP 1 and 2), for an additional 20-year period. 

The following document and the review it encompasses are requirements of NRC regulations 

implementing Section 102 of the National Environmental Policy Act of 1969 (NEPA; 42 USC 

4321) in Title 10 of the Code of Federal Regulations (CFR), Part 51 (10 CFR Part 51). In 

10 CFR 51.20(b)(2), the Commission indicates that issuing a renewed power reactor operating 

license requires preparation of an Environmental Impact Statement (EIS) or a supplement to an 

existing EIS. In addition, 10 CFR 51.95(c) states that the EIS prepared at the operating license 

renewal stage will be a supplement to the Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants (GEIS), NUREG-1437, Volumes 1 and 2 (NRC 1996; 1999).

Upon acceptance of NSP’s application, the NRC staff began the environmental review process 

described in 10 CFR Part 51 by publishing a Notice of Intent to prepare an EIS and conduct 

scoping. We conducted a site audit at the plant in August 2008 and held public scoping 

meetings on July 30, 2008, in Red Wing, Minnesota. In the preparation of this Supplemental 

Environmental Impact Statement (SEIS) for PINGP 1 and 2, we reviewed NSP’s Environmental 

Report (ER) and compared it to the GEIS, consulted with other agencies, conducted a review of 

the issues following the guidance set forth in NUREG-1555, Supplement 1, Standard Review 

Plans for Environmental Reviews for Nuclear Power Plants, Supplement 1: Operating License 

Renewal (NRC 2000), and considered the public comments received during the scoping 

process.

On June 17, 2008, the NRC and the Prairie Island Indian Community (PIIC) signed a 

Memorandum of Understanding (MOU) granting the PIIC Cooperating Agency status for 

purposes of developing and preparing certain portions of the SEIS for PINGP 1 and 2. The 

MOU recognizes PIIC’s special expertise and information as it relates to historic and 

archaeological resources, socioeconomics, land use, and environmental justice. The MOU 

between the NRC and the PIIC is a first-of-a-kind MOU dealing with the environmental review 

for a reactor license renewal. 

Proposed Action

NSP initiated the proposed Federal action – requesting renewed power reactor operating 

licenses – by submitting an application for license renewal of PINGP 1 and 2, for which the 

existing licenses (DPR-42 and DPR-60) expire on August 9, 2013 and October 29, 2014, 

respectively. NRC’s Federal action is the decision whether to renew the licenses for an 

additional 20 years. 

Purpose and Need for Action

The purpose and need for the proposed action (issuance of a renewed license) is to provide an 

option that allows for power generation capability beyond the term of a current nuclear power 

plant operating license to meet future system generating needs, as such needs may be 

determined by State, utility, and, where authorized, Federal (other than NRC) decision makers. 

This definition of purpose and need reflects the Commission’s recognition that, unless there are 
Summary

xiv

findings in the safety review required by the Atomic Energy Act of 1954 or findings in the NEPA 

environmental analysis that would lead the NRC to reject a license renewal application, the 

NRC does not have a role in the energy-planning decisions of State regulators and utility 

officials as to whether a particular nuclear power plant should continue to operate.

If the renewed licenses are issued, State regulatory agencies and NSP will ultimately decide 

whether the plant will continue to operate based on factors such as the need for power or other 

matters within the State’s jurisdiction or the purview of the owners. If the operating licenses are 

not renewed, then the facility must be shut down on or before the expiration dates of the current 

operating licenses: August 9, 2013, for Unit 1 and October 29, 2014, for Unit 2.

Environmental Impacts of License Renewal

The SEIS evaluates the potential environmental impacts of the proposed action. The 

environmental impacts from the proposed action can be SMALL, MODERATE, or LARGE. NSP 

and the NRC staff established separate processes for identifying and evaluating the significance 

of any new and significant information on the environmental impacts of license renewal of 

PINGP 1 and 2. Neither NSP nor the NRC identified information that is both new and significant 

related to Category 1 issues that would call into question the conclusions in the GEIS. Similarly, 

neither the scoping process nor the NRC has identified any new issue applicable to PINGP 1 

and 2 that has a significant environmental impact. Therefore, the NRC staff relies upon the 

conclusions of the GEIS for all the Category 1 issues applicable to PINGP 1 and 2.

Land Use

SMALL. The NRC did not identify any Category 2 impact issues for land use, nor did the staff 

identify any new and significant information during the environmental review. Therefore, there 

would be no impacts beyond those discussed in the GEIS.

Air Quality

SMALL. The NRC did not identify any Category 2 issues for the impact of transmission lines on 

air quality, nor did the staff identify any new or significant information during the environmental

review. Therefore, for plant operation during the license renewal term, there are no impacts 

beyond those discussed in the GEIS. 

However, air quality during refurbishment and maintenance activities is a Category 2 issue. The 

NRC staff concludes that the impact of vehicle exhaust emissions resulting from refurbishment 

activities would be SMALL. Potential mitigation measures include implementation of a dust 

control plan and the use of vans and workforce shift changes to reduce the number of vehicles 

on the road at any one given time.

Ground Water Use and Quality

SMALL. Ground water use conflicts: potable and service water—plants using greater than 100 

gallons per minute; and plants using cooling towers withdrawing make-up water from a small 

river) are Category 2 issues related to license renewal at PINGP 1 and 2. Information provided 

by NSP, including drawdown calculations and consumptive use calculations, was reviewed by 

the NRC staff, and staff determined that the impact of water withdrawal at PINGP 1 and 2 is 

SMALL.
Summary

xv

Surface Water Use and Quality

SMALL. Water use conflicts—plants with cooling ponds or cooling towers using make-up water 

from a small river with low flow—is a Category 2 issue related to license renewal at PINGP 1 

and 2. Withdrawals of Mississippi River water by PINGP 1 and 2 are less than 11 percent of the 

lowest annual mean flow and approximately 4.6 percent of the average river flow. Relative to 

the total flow of the Mississippi River, PINGP 1 and 2’s consumptive use and related impact to 

the river is SMALL.

Aquatic Resources

SMALL. Aquatic Resources conflicts: impingement, entrainment, and heat shock are Category 

2 issues related to license renewal at PINGP 1 and 2. Information provided by NSP, as well as 

the conclusions drawn by NRC staff, shows that the impacts of aquatic resources at PINGP 1 

and 2 are SMALL.

Terrestrial Resources

SMALL. With regard to operation of PINGP 1 and 2 during the license renewal term, the NRC 

did not identify any Category 2 issues for terrestrial resources, nor did the staff identify any new 

or significant information during the environmental review. Therefore, there are no impacts 

beyond those discussed in the GEIS.

However, the impact to terrestrial resources during refurbishment activities is a Category 2 

issue. The majority of refurbishment activities will take place on existing facility grounds at 

PINGP 1 and 2, and use of existing structures will minimize new construction. All new, 

temporary structures will be constructed on previously disturbed land. No road improvements 

would be required for delivery of the steam generators to PINGP 1 and 2 as the new steam 

generators would be offloaded from a barge to a transporter directly onto the PINGP 1 and 2 

site. Potential mitigation measures to minimize impacts to terrestrial resources include installing 

silt fences to minimize sediment transport, the use of best management practices, and the 

restoration of cleared land upon completion of construction activities.

Threatened and Endangered Species

MODERATE. Impacts to threatened and endangered species during the period of extended 

operation and during refurbishment activities are Category 2 issues. The U.S. Fish and Wildlife 

Service indicated that the Higgins eye pearly mussel (Lampsilis higginsii) is present in Upper 

Mississippi River within the vicinity of PINGP 1 and 2, though no designated critical habitat is 

present for the species in Goodhue County. The Higgins eye pearly mussel is the only 

Federally-listed threatened and endangered species in the vicinity of PINGP 1 and 2. The NRC 

staff concludes that the continued operation of PINGP 1 and 2 during the license renewal term 

is not likely to adversely affect any Federally-listed aquatic species. However, the NRC staff 

concludes the continued operation of PINGP 1 and 2 during the license renewal period is likely 

to affect State-listed mussel species and could cause long-term destabilization to certain mussel 

populations. Thus, the staff concludes that the overall impact on threatened or endangered 

aquatic species from an additional 20 years of operation would vary from species to species, but 

overall, would be MODERATE. Refurbishment activities will take place on existing facility

grounds at the PINGP 1 and 2 site, and all new, permanent structures will be constructed on 

previously disturbed land; therefore, no impact to threatened or endangered species is 

anticipated. While steam generators will travel to the PINGP 1 and 2 site by barge via the river 

system, though no changes to the river or dams are anticipated.
Summary

xvi

Human Health

SMALL. With regard to Category 1 human health issues during the license renewal term—

microbiological organisms (occupational health), noise, radiation exposures to public, 

occupational radiation exposures, and electromagnetic fields (chronic effects)—the NRC staff 

did not identify any new or significant information during the environmental review. Therefore, 

there are no impacts beyond those discussed in the GEIS. . Microbiological organisms (public 

health) and electromagnetic fields— acute effects (electric shock) are Category 2 human health 

issues. Between 2000 and 2005, the highest ambient river water temperature upstream of the 

discharge canal was 86.0 °F (30 °C), and the highest temperature downstream of the discharge 

canal was 86.4 °F (30.2 °C), both measured in August 2001. The highest temperature 

measured at the PINGP 1 and 2 discharge canals was 99 °F (37.2 °C), in August 2003. 

Maximum temperature conditions could allow for the presence of thermophilic microbiological 

organisms; however, given the growth rate of these organisms, it is not expected that the period 

of time in which the heated discharge water moves through the discharge canal would allow for 

any noticeable impact on growth rates of microbiological organisms. Additionally, potential 

thermophilic microbiological organisms present in the discharge canal would likely be in limited 

numbers and would not be expected to cause a significant risk to public health. Additionally, the 

PINGP 1 and 2 discharge canal and adjacent portions of the Mississippi River do not allow for 

public access; therefore, the impact is SMALL.

NRC staff reviewed NSP’s analysis of electromagnetic fields—acute shock resulting from 

induced charges in metallic structures, and verified that none of PINGP 1 and 2’s in-scope 

transmission lines have the capability to induce shock greater than 5 milliamperes in a vehicle 

parked beneath the lines. This finding conforms with National Electric Safety Code provisions 

for preventing electric shock from induced current. Potential mitigation measures include limiting 

public access to transmission line structures, installing signs at road crossings, and increasing 

transmission line clearances. The NRC staff considers the GEIS finding of “uncertain” for 

electromagnetic fields—chronic effects still appropriate and will continue to follow developments 

on this issue.

Socioeconomics

SMALL to MODERATE. The NRC did not identify any Category 1 public services and aesthetic 

impacts, or new and significant information during the environmental review. Therefore, there 

would be no impacts beyond those discussed in the GEIS. Category 2 socioeconomic impacts 

include housing impacts, public services (public utilities), offsite land use, public services (public 

transportation), historic and archaeological resources, and environmental justice. Since PINGP 

1 and 2 are located in a high-density population area, and growth control measures are not in 

effect, any changes in PINGP 1 and 2 employment would have little noticeable effect on 

housing availability in the surrounding area. NSP has indicated that the steam generator 

replacement would require a one-time increase in the number of refueling outage workers for up 

to 80 days, which would create an additional demand for temporary (rental) housing in the 

immediate vicinity of PINGP 1 and 2. This also applies to offsite land use and transportation 

issues – because non-outage employment levels at PINGP 1 and 2 would remain relatively 

unchanged during the license renewal period, there would be no land use impacts related to 

population or tax revenues, and no transportation impacts. Category 2 socioeconomic impacts 

related to refurbishment at PINGP 1 and 2 would be SMALL, as the PINGP Unit 2 steam 

generator project is expected to require a one-time increase of outage workers for 

approximately 80 days—a short duration of time.

Impacts to known historical and archeological resources are SMALL to MODERATE from 

continued operation of PINGP 1 and 2 during the license renewal term. These impacts are 
Summary

xvii

potentially mitigated with the implementation of new commitments proposed by NSP. These 

commitments are described in chapter 4 of this SEIS. Since PINGP 1 and 2 are situated in an 

archaeologically sensitive area, continuing to develop Cultural Resources Management Plan in 

addition to NSP’s review procedures would serve to integrate cultural resource considerations 

with ongoing PINGP 1 and 2 activities. Additionally, training of PINGP 1 and 2 staff in the 

Section 106 process would ensure that informed decisions are made when considering the 

effects of future projects on historic and archaeological resources. Lands that have not been 

surveyed should be investigated by a professional archaeologist prior to any ground 

disturbance. Because refurbishment activities will occur on previously disturbed land, the 

impacts associated with refurbishment are not expected to adversely affect historic or 

archaeological sites in the area of PINGP Unit 2. 

Regarding environmental justice, an analysis of minority and low-income populations residing 

within a 50-mile (80-kilometer) radius of PINGP 1 and 2 indicated there would be no 

disproportionately high and adverse impacts to these populations from the continued operation 

of PINGP 1 and 2 during the license renewal period. Additionally, based on recent monitoring 

results, concentrations of contaminants in native leafy vegetation, soils and sediments, surface 

water, and fish in areas surrounding PINGP 1 and 2 have been low (at or near the threshold of 

detection) and seldom above background levels. Consequently, no disproportionately high and 

adverse human health impacts would be expected in special pathway receptor populations in 

the region as a result of subsistence consumption of fish and wildlife.

Severe Accident Mitigation Alternatives

Since PINGP 1 and 2 had not previously considered alternatives to reduce the likelihood or 

potential consequences of a variety of highly uncommon but potentially severe accidents, NRC 

regulation 10 CFR 51.53(c)(3)(ii)(L) requires that PINGP 1 and 2 evaluate Severe Accident 

Mitigation Alternatives (SAMAs) in the course of license renewal review. SAMAs are potential 

ways to reduce the risk or potential impacts of uncommon but potentially severe accidents, and 

may include changes to plant components, systems, procedures, and training.

Based on our review of potential SAMAs, we conclude that PINGP 1 and 2 made a reasonable, 

comprehensive effort to identify and evaluate SAMAs. Based on the review of the SAMAs for 

PINGP 1 and 2, and the plant improvements already made, we conclude that none of the 

potentially cost-beneficial SAMAs relate to adequately managing the effects of aging during the 

period of extended operation; therefore, they need not be implemented as part of the license 

renewal pursuant to 10 CFR Part 54.

Alternatives

We considered the environmental impacts associated with alternatives to license renewal. 

These alternatives include other methods of power generation and not renewing the PINGP 1 

and 2 operating license (the no-action alternative). Replacement power options considered 

were 1) gas-fired combined-cycle plant at the PINGP 1 and 2 site and an undetermined 

alternate site; 2) a combination including a gas-fired unit, wind power, conservation, and woodwaste biomass; and 3) a combination including continued operation of one of the two PINGP

units, wind power, and conservation. Wherever possible, we evaluated potential environmental 

impacts for these alternatives located both at the PINGP 1 and 2 site and at some other 

unspecified alternate location. We evaluated each alternative using the same impact areas that 

we used in evaluating impacts from license renewal. The results of this evaluation are 

summarized in the following table.

All alternatives capable of meeting the needs currently served by PINGP 1 and 2 entail 

potentially equal or greater impacts than the proposed action of license renewal of 
Summary

xviii

PINGP 1 and 2. The no-action alternative does not meet the purpose and need of this SEIS, 

though if it triggers either combination alternative 1 or 2 to replace the capacity currently 

supplied by PINGP 1 and 2, it could result in an overall SMALL impact, as well.

Alternative

Summary of Environmental Impacts of Proposed Action and Alternatives

Impact Area

Air Quality

Ground Water

Surface Water

Aquatic and 

Terrestrial 

Resources

Human Health

Socioeconomics

Waste Management

PINGP 1 and 2 

License Renewal SMALL SMALL SMALL SMALL SMALL SMALL to 

MODERATE SMALL

Gas-fired at PINGP 

1 and 2 site MODERATE SMALL SMALL SMALL to 

MODERATE SMALL SMALL to 

MODERATE SMALL

Gas-fired at 

Alternative Site MODERATE SMALL SMALL SMALL to 

MODERATE SMALL SMALL to MODERATE SMALL

Combination 

Alternative 1(a) MODERATE SMALL SMALL to 

MODERATE MODERATE MODERATE SMALL to 

MODERATE SMALL

Combination 

Alternative 2(b) SMALL SMALL SMALL SMALL to 

MODERATE SMALL SMALL to MODERATE SMALL

No Action 

Alternative SMALL SMALL SMALL SMALL SMALL SMALL to 

MODERATE SMALL

(a)Combination Alternative 1 consists of gas-fired generation, wood-fired generation, wind power, and conservation

(b)Combination Alternative 2 consists of continued operation of one of the two PINGP 1 and 2 units, wind power, and 

conservation

Recommendation

The Nuclear Regulatory Commission’s recommendation is that the adverse environmental 

impacts of license renewal for PINGP 1 and 2 are not great enough to deny the option of license 

renewal for energy-planning decision makers. This determination is based on (1) the analysis 

and findings in the Generic Environmental Impact Statement for License of Nuclear Plants 

(GEIS), NUREG-1437; (2) the Environmental Report submitted by NSP; (3) consultation with 

Federal, State, Tribal, and local agencies; (4) the NRC staff’s own independent review; and (5) 

the NRC staff’s consideration of public comments received during the scoping process and draft 

SEIS comment period.
xix

ABBREVIATIONS AND ACRONYMS

ac acre

AEA Atomic Energy Act of 1954

AEC U.S. Atomic Energy Commission

AEO Annual Energy Outlook

ALARA As Low As is Reasonably Achievable

APE area of potential effect

APP Avian Protection Plan

BTU/kWh British thermal units per kilowatt hour

BO Biological Opinion

°C degrees Celsius

CAA Clean Air Act

CDC U.S. Center for Disease Control and Prevention

CDF Core Damage Frequency

CDM Clean Development Mechanism

CEQ Council on Environmental Quality

CFR Code of Federal Regulations

cfs cubic feet per second

Ceq/kWh carbon equivalent per kilowatt-hour

cm centimeter

CO carbon monoxide

CO2 carbon dioxide

CWA Clean Water Act

DBA design-basis accident

DOE U.S. Department of Energy

DPR demonstration power reactor

EHA essential habitat area

EIA Energy Information Administration (of DOE)

EIS environmental impact statement

ELF-EMF extremely low frequency-electromagnetic field

EMS environmental management system

ER environmental report

EPA U.S. Environmental Protection Agency

EPCRA Emergency Planning and Community Right-to-Know Act

ESA Endangered Species Act of 1973

°F degrees Fahrenheit

FES Final Environmental Statement

fps feet per second

FR Federal Register

FSAR Final Safety Analysis Report

ft feet

ft/s feet per second

FWS U.S. Fish and Wildlife Service
Abbreviations and Acronyms

xx

GE General Electric Company

GEIS Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants, NUREG-1437

GHG greenhouse gas

gpm gallons per minute

hc hectare

HID high intensity discharge

in. inch

Inc. Incorporated

IPE Individual Plant Examination

IPEEE Individual Plant Examination of External Events

ISFSI independent spent fuel storage installation

ISLOCA interfacing system loss-of-coolant accidents

kg/cm2 kilograms per square centimeter

LLC limited liability corporation

LOCA loss of coolant accident

m meter

MACCS2 MELCOR Accident Consequence Code System 2

MDH Minnesota Department of Health

mgd million gallons per day

mGy milligray (unit of absorbed radiation dose)

MNDNR Minnesota Department of Natural Resources

MOU memorandum of understanding

MPCA Minnesota Pollution Control Agency

mrad millirad (unit of absorbed radiation dose)

m/s meters per second

m3

/s cubic meters per second

mSv millisievert

MT metric tonne

MTU metric tonne uranium

MW megawatt

MWd megawatt days

MWe megawatt-electric

MWt megawatt-thermal

NA not applicable

NAAQS National Ambient Air Quality Standards

NAS National Academy of Sciences

NEPA National Environmental Policy Act of 1969

NHPA National Historic Preservation Act

NIEHS National Institute of Environmental Health Sciences

NMC Nuclear Management Company, LLC

NOx nitrogen oxide(s)

NPDES National Pollutant Discharge Elimination System

NRC U.S. Nuclear Regulatory Commission

NRHP National Register of Historic Places
Abbreviations and Acronyms

xxi

NSP Northern States Power Co. – Minnesota 

NUREG NRC Regulatory Guide

O3 ozone

PAM primary amoebic meningoencephalitis

PCB polychlorinated biphenol

pCi/L picocuries per liter

PFOS perfluorooctanesulfonic acid

PIIC Prairie Island Indian Community

PINGP 1 and 2 Prairie Island Nuclear Generating Plant, Units 1 and 2

PM2.5 particulate matter, 2.5 microns or less in diameter

PM10 particulate matter, 10 microns or less in diameter

PRA Probabilistic Risk Assessment

psi pound per square inch

PWR pressurized water reactor

RCRA Resource Conservation and Recovery Act

rem Röntgen equivalent man

REMP radiological environmental monitoring program

RM river mile

ROW(s) right-of-way(s)

RWST refueling water storage tank

SAMA Severe Accident Mitigation Alternative

SAR Safety Analysis Report

SD surface discharge

SEIS supplemental environmental impact statement

SER Safety Evaluation Report

SGTR steam generator tube rupture

SHPO State Historic Preservation Office

SO2 sulfur dioxide

Sv sievert

TCLP toxic characteristic leaching procedure

U Uranium

U.S. United States

USACE United States Army Corps of Engineers

U.S.C. United States Code

USGS U.S. Geological Survey

WDNR Wisconsin Department of Natural Resources

WIDHS Wisconsin Department of Health Services

WS waste streams

1-1

1.0 PURPOSE AND NEED FOR ACTION

Under the U.S. Nuclear Regulatory Commission’s (NRC’s) environmental protection regulations 

in Title 10, Part 51, of the Code of Federal Regulations (10 CFR 51), which implement the 

National Environmental Policy Act of 1969 (NEPA), issuance of a new nuclear power plant 

operating license requires the preparation of an environmental impact statement (EIS). 

The Atomic Energy Act of 1954 (AEA) originally specified that licenses for commercial power 

reactors be granted for up to 40 years with an option to renew for up to another 20 years. The 

40-year licensing period was based primarily on economic and antitrust considerations rather 

than on technical limitations of the nuclear facility.

The decision to seek a license renewal rests entirely with nuclear power facility owners and 

typically is based on the facility’s economic viability and the investment necessary to continue to 

meet NRC safety and environmental requirements. The NRC makes the decision to grant or 

deny a license renewal, based on whether the applicant has demonstrated that the 

environmental and safety requirements in the NRC’s regulations can be met during the period of 

extended operation. 

1.1 Proposed Federal Action

Northern States Power Co. (NSP) [formerly Nuclear Management Company, LLC. (NMC)] 

initialized the proposed Federal action by submitting an application for license renewal of Prairie 

Island Nuclear Generating Plant, Units 1 and 2 (PINGP 1 and 2), for which the existing licenses

DPR-42 (Unit 1) and DPR-60 (Unit 2) expire August 9, 2013, and October 29, 2014, 

respectively. NRC’s Federal action is the decision whether to renew the licenses for an 

additional 20 years. 

1.2 Purpose and Need for the Proposed Federal Action

The purpose and need for the proposed action (issuance of a renewed license) is to provide an 

option that allows for power generation capability beyond the term of a current nuclear power 

plant operating license to meet future system generating needs, as such needs may be 

determined by State, utility, and, where authorized, Federal (other than NRC) decision makers.

This definition of purpose and need reflects the Commission’s recognition that, unless there are 

findings in the safety review required by the AEA or findings in the NEPA environmental 

analysis that would lead the NRC to reject a license renewal application, the NRC does not 

have a role in the energy-planning decisions of State regulators and utility officials as to whether 

a particular nuclear power plant should continue to operate.

If the renewed license is issued, State regulatory agencies and NSP will ultimately decide 

whether the plant will continue to operate based on factors such as the need for power or other 

matters within the State’s jurisdiction or the purview of the owners. If the operating license is not 

renewed, then the facility must be shut down on or before the expiration date of the current 

operating license, August 9, 2013, for Unit 1 and October 29, 2014, for Unit 2.

1.3 Major Environmental Review Milestones

NSP submitted an environmental report (NMC 2008) as part of its license renewal application 

(NMC 2008b) in April 2008. After reviewing the application and the environmental report (ER) 

for sufficiency, the NRC staff published a Notice of Acceptability and Opportunity for Hearing on 

June 17, 2008, in the Federal Register (Volume 73, p. 34335, (73 FR 34335)). Then, on 
Purpose and Need for Action

1-2

July 22, 2008, the NRC published another notice in the Federal Register (73 FR 42628) on its 

intent to conduct scoping, thereby beginning the 60-day scoping period. 

The NRC held two public scoping meetings on July 30, 2008, in Red Wing, Minnesota. The 

NRC report entitled, “Environmental Impact Statement Scoping Process Summary Report for 

Prairie Island Nuclear Generating Plant, Units 1 and 2,” dated May 1, 2009, presents the 

comments received during the scoping process in their entirety (NRC 2009). Appendix A to this 

supplemental environmental impact statement (SEIS) presents the comments considered to be 

within the scope of the environmental license renewal review and the associated NRC 

responses. 

In order to independently verify information provided in the ER, the NRC staff conducted a site 

audit at the PINGP 1 and 2 site in August of 2008. During the site audit, the NRC staff met with 

plant personnel, reviewed specific documentation, toured the facility, and met with interested 

Federal, State, and local agencies. A summary of that site audit and a list of the attendees is 

contained in the Summary of site audit related to the review of the license renewal application 

for PINGP 1 and 2 published January 27, 2009 (NRC 2009a).

Upon completion of the scoping period and site audit, the NRC staff compiled its findings in a

SEIS (Figure 1-1). The draft document was made available for public comment for 75 days. 

During that time, NRC staff hosted two public meetings and collected public comments. Based 

on the information received from the public during the comment period and from the public 

meetings, the NRC staff amended the SEIS findings, as necessary, and published the final 

SEIS.

Figure 1-1. Environmental Review Process.

The environmental review provides opportunities for public involvement.
Purpose and Need for Action

1-3

The NRC has established a license renewal process that can be completed in a reasonable 

period of time with clear requirements to assure 

safe plant operation for up to an additional 20 

years of plant life. The safety review, which 

documents its finding in a Safety Evaluation 

Report, is conducted simultaneously with the 

environmental review. The findings in both the 

SEIS and the Safety Evaluation Report (SER) are 

both factors in the Commission’s decision to either 

grant or deny the issuance of a renewed license. 

1.4 Generic Environmental Impact 

Statement

The NRC performed a generic assessment of the 

environmental impacts associated with license renewal to improve the efficiency of the license 

renewal process. NUREG-1437, Generic Environmental Impact Statement for License Renewal 

of Nuclear Power Plants (referred to as the GEIS), documents the results of the NRC staff’s 

systematic approach to evaluating the environmental consequences of renewing the licenses of 

individual nuclear power plants and operating them for an additional 20 years (NRC 1996, 

1999).

1

The GEIS establishes 92 separate issues for the NRC staff to independently verify. Of these, 

the staff determined that 69 are generic to all plants (Category 1), while 21 issues do not lend 

themselves to generic consideration (Category 2). Two other issues remained uncategorized; 

environmental justice and the chronic effects of electromagnetic fields must be evaluated on a 

site-specific basis. Appendix B to this report lists all 92 issues. 

 The NRC staff analyzed in detail and resolved those environmental issues that could be 

resolved generically in the GEIS.

For each potential environmental issue, the GEIS (1) describes the activity that affects the 

environment, (2) identifies the population or resource that is affected, (3) assesses the nature 

and magnitude of the impact on the affected population or resource, (4) characterizes the 

significance of the effect for both beneficial and adverse effects, (5) determines whether the 

results of the analysis apply to all plants, and (6) considers whether additional mitigation

measures would be warranted for impacts that would have the same significance level for all 

plants. 

The NRC’s standard of significance for impacts was established using the Council on 

Environmental Quality (CEQ) terminology for “significant.” The NRC established three levels of 

significance for potential impacts—SMALL, MODERATE, and LARGE, as defined below.

SMALL – Environmental effects are not detectable or are so minor that they will neither 

destabilize nor noticeably alter any important attribute of the resource.

MODERATE – Environmental effects are sufficient to alter noticeably, but not to destabilize, 

important attributes of the resource.

LARGE – Environmental effects are clearly noticeable and are sufficient to destabilize important 

attributes of the resource.

The GEIS includes a determination whether the analysis of the environmental issue can be 

applied to all plants and whether additional mitigation measures would be warranted (Figure 1-

 1 The NRC originally issued the GEIS in 1996 and issued Addendum 1 to the GEIS in 1999. Hereafter, all 

references to the “GEIS” include the GEIS and Addendum 1.

Significance indicates the 

importance of likely environmental 

impacts and is determined by 

considering two variables: context

and intensity. 

Context is the geographic, 

biophysical, and social context in 

which the effects will occur. 

Intensity refers to the severity of the 

impact, in whatever context it occurs. 
Purpose and Need for Action

1-4

2). Issues are assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, 

Category 1 issues are those that meet all of the following criteria:

1) The environmental impacts associated with the issue have been determined 

to apply either to all plants or, for some issues, to plants having a specific 

type of cooling system or other specified plant or site characteristics;

2) A single significance level (i.e., SMALL, MODERATE, or LARGE) has been 

assigned to the impacts (except for collective offsite radiological impacts from 

the fuel cycle and from high-level waste and spent fuel disposal); and

3) Mitigation of adverse impacts associated with the issue has been considered 

in the analysis, and it has been determined that additional plant-specific 

mitigation measures are likely not to be sufficiently beneficial to warrant 

implementation.

For generic issues (Category 1), no additional site-specific analysis is required in the SEIS 

unless new and significant information is identified. Chapter 4 of this report presents the 

process for identifying new and significant information. Site-specific issues (Category 2) are 

those that do not meet one or more of the criterion for Category 1 issues, and therefore, 

additional site-specific review for these issues is required. The SEIS documents the results of 

that site-specific review.
Purpose and Need for Action

1-5

Figure 1-2. Environmental Issues Evaluated During License Renewal. 92 issues were 

initially evaluated in the GEIS. A site-specific analysis is required for

23 of those 92 issues.

1.5 Supplemental Environmental Impact Statement

The SEIS presents an analysis that considers the environmental effects of the continued 

operation of PINGP 1 and 2, alternatives to license renewal, and mitigation measures for 

minimizing adverse environmental impacts. Chapter 8 contains analysis and comparison of the 

potential environmental impacts from alternatives while Chapter 9 presents the preliminary 

recommendation to the Commission on whether or not the environmental impacts of license 

renewal are so great that preserving the option of license renewal would be unreasonable. The 

recommendation will be made after consideration of comments received during the public 

comment period on the SEIS.

In the preparation of this SEIS for PINGP 1 and 2, the NRC staff undertook the following 

activities:

• reviewed the information provided in the NSP ER, 

• consulted with other Federal, State, and local agencies, 
Purpose and Need for Action

1-6

New and significant information either:

(1) identifies a significant environmental issue 

not covered in the GEIS, or (2) was not 

considered in the analysis in the GEIS and 

leads to an impact finding that is different from 

the finding presented in the GEIS.

• conducted an independent review of the issues during the site audit, and

• considered the public comments received during the scoping process.

New information can be identified from a 

number of sources, including the 

applicant, NRC, other agencies, and

public comments. If a new issue is 

revealed, then it is first analyzed to 

determine whether it is within the scope 

of the license renewal evaluation. If it is 

not addressed in the GEIS, the NRC 

then determines its significance and 

documents its analysis in the SEIS.

1.6 Cooperating Agencies

The federal government owes a general trust responsibility to federally recognized Indian 

Tribes. In the absence of a specific duty placed on the government with respect to Indians, an 

independent regulatory agency, such as the NRC, discharges its obligations under the trust 

responsibility by complying with regulations and statutes designed to protect the public at large, 

in this case, the Atomic Energy Act (AEA) and the National Environmental Policy Act (NEPA). 

Trust Responsibility:

In June 2008, the NRC and the Prairie Island Indian Community (PIIC) entered into a 

Memorandum of Understanding (MOU). The MOU acknowledges the PIIC’s special expertise in 

the areas of historic and archaeological resources, socioeconomics, land use, and 

environmental justice as they relate to license renewal for PINGP 1 and 2. The MOU provides a 

mechanism by which the PIIC can assist the NRC in preparing the Supplemental Environmental 

Impact Statement (SEIS). The MOU establishes a Cooperating Agency relationship between 

the NRC and the PIIC and describes the responsibilities of the two entities and the process they 

will use to produce a SEIS that incorporates and reflects the PIIC’s views in the areas of its 

special expertise. The MOU can be found in ADAMS at accession number ML081610273.

The Memorandum of Understanding:

In preparing the draft and final versions of this SEIS, the PIIC and NRC worked together to 

develop a comprehensive evaluation of the areas covered by the MOU. A number of meetings 

were held between the PIIC and NRC staff to fully understand those subject areas covered by 

the MOU. The NRC considered all input by the PIIC; however, the staff did not agree with every 

comment. In Chapters 2, 3, 4, 5, and 8, statements written by the PIIC are included to present 

its view-points on the areas covered by the MOU. These written statements are indented to 

distinguish them from NRC text. 

The PIIC is a Federally-recognized Indian tribe organized under the Indian Reorganization Act 

of 1934. The PIIC’s Constitution and By-Laws, adopted by tribal members on May 23, 1936, 

and subsequently approved by the Secretary of the Interior on June 20, 1936, provide the terms 

and conditions under which the tribe is governed. The Constitution and By-laws provide that the 

Community Council (also known as the Tribal Council) shall be the governing body for the PIIC. 

The five-member Tribal Council consists of a President, Vice-President, Secretary, Treasurer, 

and Assistant Secretary/Treasurer, each of whom is elected to a two-year term. (PIIC 2008) 

The PIIC Tribal Government
Purpose and Need for Action

1-7

1.7 Consultations

The Endangered Species Act of 1973, as amended; the Magnuson-Stevens Fisheries 

Conservation and Management Act of 1996, as amended; and the National Historic 

Preservation Act of 1966 require that Federal agencies consult with applicable State and 

Federal agencies and groups before taking action that may affect endangered species, 

fisheries, or historic and archaeological resources, respectively. Below are the agencies and 

groups with whom the NRC consulted; Appendix D to this report includes copies of consultation 

documents.

Advisory Council on Historic Preservation, Washington, D.C.

Bureau of Indian Affairs, Fort Snelling, Minnesota

Minnesota Department of Natural Resources, St. Paul, Minnesota

Prairie Island Indian Community, Welch, Minnesota

State Historic Preservation Office, St. Paul, Minnesota

Wisconsin Department of Natural Resources, Madison, Wisconsin

U.S. Fish and Wildlife Service, Bloomington, Minnesota

1.8 Correspondence

During the course of the environmental review, the NRC staff contacted the following Federal, 

State, regional, local, and tribal agencies. Appendix E to this report contains a chronological list 

of all documents sent and received during the environmental review.

Advisory Council on Historic Preservation, Washington, D.C.

Bois Forte Reservation, Nett Lake, Minnesota

Bureau of Indian Affairs, Fort Snelling, Minnesota

Cheyenne River Sioux Tribe, Eagle Battle, South Dakota

Crow Creek Sioux Tribe, Fort Thompson, South Dakota

Dakota County Offices, Hastings, Minnesota

Flandreau Santee Sioux Tribe, Flandreau, South Dakota

Florence Township Commission, Frontenac, Minnesota

Fond du Lac Reservation, Cloquet, Minnesota

Goodhue County Courthouse, Red Wing, Minnesota

Goodhue County Offices, Red Wing, Minnesota

Goodhue County Land Use Management, Red Wing, Minnesota

Grand Portage Reservation, Grand Portage, Minnesota

Ho-Chunk Nation, Black River Falls, Wisconsin

Leech Lake Reservation, Cass Lake, Minnesota

Lower Brule Sioux Tribe, Lower Brule, South Dakota

Lower Sioux Indian Community of Minnesota, Morton, Minnesota
Purpose and Need for Action

1-8

Mayor, City of Lake City, Minnesota

Mille Lacs Band of Ojibwe Indians, Onamia, Minnesota

Minnesota Chippewa Tribe, Cass Lake, Minnesota

Minnesota Department of Commerce, St. Paul, Minnesota

Minnesota Department of Health, St. Paul, Minnesota

Minnesota Department of Natural Resources, St. Paul, Minnesota

Minnesota Pollution Control Agency, St. Paul, Minnesota

Oglala Sioux Tribe, Pine Ridge, South Dakota

Prairie Island Indian Community, Welch, Minnesota

Red Lake Band of Chippewa Indians of Minnesota, Red Lake, Minnesota

Red Wing City Council, Red Wing, Minnesota

Rosebud Sioux Tribe, Rosebud, South Dakota

Santee Sioux Nation, Niobrara, Nebraska

Sisseton-Wahpeton Oyate of the Lake, Agency Village, South Dakota

Shakopee Mdewakanton Sioux Community, Prior Lake, Minnesota

Spirit Lake Tribe, Fort Totten, North Dakota

State Historic Preservation Office, St. Paul, Minnesota

Standing Rock Sioux Tribe, Fort Yates, North Dakota

St. Croix Chippewa Indians of Wisconsin, Webster, Wisconsin

Turtle Mountain Band of Chippewa, Belcourt North Dakota

Upper Sioux Community of Minnesota, Granite Falls, Minnesota

U.S. Fish and Wildlife Service, Bloomington, Minnesota

White Earth Reservation, White Earth, Minnesota

Winnebego Tribe, Winnebego, North Dakota

Wisconsin Department of Natural Resources, Madison, Wisconsin

Yankton Sioux Tribe, Marty, South Dakota
Purpose and Need for Action

1-9

A list of persons who received a copy of the SEIS is provided below:

Peter M. Glass, Xcel 

Energy Services, Inc.

Manager, Regulatory 

Affairs, Northern States 

Power Co.

Manager, Minnesota 

Attorney General’s Office

Resident Inspector's Office, 

NRC

Philip R. Mahowald, Prairie 

Island Indian Community

Gene Eckholt, Northern 

States Power Co.

Heather Westra, Prairie 

Island Indian Community

Administrator, Goodhue 

County Courthouse

Jim Holthaus, Northern 

States Power Co.

Katie Himanga, City of Lake 

City

Commissioner, Minnesota 

Department of Commerce

Tribal Council, Prairie 

Island Indian Community

Nuclear Asset Manager, 

Xcel Energy, Inc.

Dennis L. Koehl, Northern 

States Power Co.

Joel P. Sorenson, Northern 

States Power Co.

Kay Kuhlmann, Red Wing 

City Council

Joan Marshman Deanna Sheely, Red Wing 

City Council

Kristen Eide-Tollefson, 

Florence Township 

Commission

Lisa Hanni, Goodhue 

County Land Use 

Management

Nancy Shouweiller, Dakota 

County, Fourth District

Carolyn Homsten, CPA, 

Goodhue County

Mr. Don L. Klima, Director, 

Advisory Council on 

Historic Preservation

Terrance Virden, U.S. 

Bureau of Indian Affairs

Stanley Crooks, Shakopee 

Mdewakanton Sioux 

Community

John L. Stine, Minnesota 

Department of Health

Ms. Lisa A. Joyal, 

Minnesota Department of 

Natural Resources

Stan Ellison, Shakopee 

Mdewakanton Sioux 

Community

Leonard Wabasha, 

Shakopee Mdewakanton 

Sioux Community

Emily Rusch, Wisconsin 

Department of Natural 

Resources

John Wurst Joe Ellingson Michael McKay, Wacouta 

Township

Elaine and Arlen Diercks, 

Hay Creek Township

Doub Lansing, Maiden 

Rock Village

Matrix Energy Solutions

Mr. Ronald Johnson, Prairie 

Island Indian Community

Mr. Kevin Jensvold, Upper 

Sioux Community of 

Minnesota

Jean Stacy, Lower Sioux 

Indian Community of 

Minnesota

Joseph Brings Plenty, 

Cheyenne River Sioux 

Tribe

Lester Thompson, Crow 

Creek Sioux Tribal Council

Joshua Weston, Flandreau 

Santee Sioux Executive 

Committee

Michael Jandreau, Lower 

Brule Sioux Tribal Council

John Yellow Bird Steele, 

Oglala Sioux Tribal Council

Rodney Bordeaux, 

Rosebud Sioux Tribal 

Council

Roger Trudell, Santee 

Sioux Nation

Michael Selvage, Sr., 

Sisseton-Wahpeton Oyate 

of the Lake

Myra Pearson, Spirit Lake 

Tribal Council
Purpose and Need for Action

1-10

Ron His Horse Is Thunder, 

Standing Rock Sioux Tribal 

Council

Marcus D. Wells, Jr., Three 

Affiliated Tribes Business 

Council

David Brien, Turtle 

Mountain Band of 

Chippewa

Matthew Pilcher, 

Winnebago Tribal Council

Robert Cournoyer, Yankton 

Sioux Tribal Business & 

Claims Committee

Wilfrid Cleveland, HoChunk Nation

Norman Deschampe, 

Minnesota Chippewa Tribe

Tony Sullins, U.S. Fish & 

Wildlife Service

Thomas A. Lovejoy, 

Wisconsin Department of 

Natural Resources

Kevin Leecy, Bois Forte 

Reservation Business

Karen R. Diver, Fond du 

Lac Reservation Business 

Committee

Norman Deschampe, 

Grand Portage Reservation 

Business Committee

George Goggleye, Leech 

Lake Reservation Business 

Committee

Melanie A. Benjamin, Mille 

Lacs Band of Ojibwe 

Indians

Erma Vizenor, White Earth 

Reservation Business 

Committee

Floyd Jourdain, Red Lake 

Band of Chippewa Indians 

of Minnesota

Hazel Hindsley, St. Croix 

Chipewa Indians of 

Wisconsin 

Mr. Dennis A. Gimmestad, 

Minnesota Historical 

Society

Katrina Kessler, Minnesota 

Pollution Control Agency

Carol A. Overland, 

Overland Law Office

Lea Foushee, NAWO

Gary Wege, U.S. Fish and 

Wildlife Service

Nick Schaff, Wisconsin 

Department of Natural 

Resources

1.9 Status of Compliance

NSP is responsible for complying with all NRC regulations and other applicable Federal, State, 

and local requirements; Appendix H to the GEIS describes some of the major Federal statutes. 

Table 1-1 lists the numerous permits and licenses issued by Federal, State, and local authorities 

for activities at PINGP 1 and 2. 
Purpose and Need for Action

1-11

Table 1-1. Licenses and Permits. Existing environmental authorizations for PINGP 1 and 2, 

Operations.

Permit Number Responsible Agency

Operating Licenses DPR-42 and 

DPR-60 U.S. NRC

Certification of the Environmental 

Lab 027-049-218 Minnesota Department of 

Health

Construction of intake canal 

system

Docket 050-282 

and 050-306

Minnesota Department of 

Natural Resources

Construction of discharge canal 

system

Docket 050-282 

and 050-306

Minnesota Department of 

Natural Resources

National Pollutant Discharge 

Elimination System Permit MN0004006 Minnesota Pollution Control Agency

Fish, mussels, and icthyoplankton 

collection Permit

MN State rules

15975 and 

15994

Minnesota Department of 

Natural Resources

Surface Water Appropriation 

Permit 690172 Minnesota Department of 

Natural Resources

Ground Water Appropriation 

Permit

Permit Nos. 

690171, 

785153, 

865114, and 

965042

Minnesota Department of 

Natural Resources

Hazardous materials shipments UPR-211635-

MN

Minnesota Department of 

Transportation

Industrial wastewater discharge to 

Mississippi River Permit MN0004006

Minnesota Pollution 

Control Agency, Industrial 

Division

Operation of air emissions system 

for an electric utility power 

generation system Permit

00000001-003 Minnesota Pollution 

Control Agency

Operation of oil-fired boiler and 

diesel-fired engines for emergency 

power, pump cooling water, and 

fire fighting system Permit

04900030-004

Minnesota Pollution 

Control Agency

Above ground storage tank 

registration MPCA 51557 Minnesota Pollution Control Agency

Hazardous Waste Generator 

License, Small Quantity MND049537780 Minnesota Pollution 

Control Agency

Transportation of radioactive waste 

into the State of Tennessee Permit T-MN003-10

State of Tennessee 

Department of 

Environmental and 

Conservation Division of 

Radiological Health
Purpose and Need for Action

1-12

Permit Number Responsible Agency

Transportation of radioactive waste 

into the State of Utah Permit 0402 002 748

State of Utah Department 

of Environmental Quality 

Division of Radiation 

Control

Collect fish and ichthyoplankton for 

radiological and biological 

monitoring

 SCP-WCR-20-

C-10

Wisconsin Department of 

Natural Resources

Maintenance dredging and erosion 

control discharge canal General 

Permit

GP/LOP-98-MN U.S. Army Corps of 

Engineers

Air quality monitoring station at 

Lock and Dam Number 3 License 

DACW37-3-06-

0071

U.S. Army Corps of 

Engineers

Maintenance dredging in front of 

the River Intake Structure 

Dredging Permit

GP-01-MN U.S. Army Corps of 

Engineers 

Hazardous materials shipments 

Registration

062706 552 

0090

U.S. Department of 

Transportation 

Retrieve, transport, and 

temporarily possess carcasses of 

migratory birds as well as collect, 

stabilize, and transport sick/injured 

migratory birds Wildlife Permit

MB074020-0 U.S. Fish and Wildlife 

Service

1.10 References

10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

Protection Regulations for Domestic Licensing and Related Regulatory Functions.”

73 FR 34335. U.S. Nuclear Regulatory Commission, Washington D.C. “Nuclear Management 

Company, LLC, Prairie Island Nuclear Generating Plant, Units 1 and 2; Notice of Acceptance for 

Docketing of the Application and Notice of Opportunity for Hearing Regarding Renewal of 

Facility Operating License Nos. DPR– 42 and DPR–60 for an Additional 20- Year Period.” 

Federal Register, Vol. 73, No. 117, pp34335-34337, June 17, 2008.

73 FR 42628. U.S. Nuclear Regulatory Commission, Washington D.C. “Nuclear Management 

Company, LLC.; Prairie Island Nuclear Generating Plant, Units 1 and 2; Notice of Intent To 

Prepare an Environmental Impact Statement and Conduct Scoping Process.” Federal Register: 

Vol. 73, No. 141, pp42628-42630, July 22, 2008.

Atomic Energy Act of 1954. 42 U.S.C. 2011, et seq.

Endangered Species Act of 1973. 16 U.S.C. 1531, et seq.

Magnuson-Stevens Fishery Conservation and Management Act, as amended by the 

Sustainable Fisheries Act of 1996. 16 U.S.C. 1855, et seq.

National Environmental Policy Act of 1969. 42 U.S.C. 4321, et seq.
Purpose and Need for Action

1-13

National Historic Preservation Act. 16 U.S.C. 470, et seq.

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage, Redwing, Minnesota, April 2008, ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NMC (Nuclear Management Company, LLC). 2008b. Application for Renewed Operating 

Licenses , Prairie Island Nuclear Generating Plant, Units 1 and 2, April 2008. ADAMS No.

ML081130673.

NRC (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, NUREG-1437, Volumes 1 and 2, Washington, D.C. 

ADAMS Nos. ML040690705 and ML040690738.

NRC (U.S. Nuclear Regulatory Commission). 1999. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, Main Report, “Section 6.3 – Transportation, Table 9.1, 

Summary of findings on NEPA issues for license renewal of nuclear power plants, Final Report,” 

NUREG-1437, Volume 1, Addendum 1, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 2009. Environmental Impact Statement Scoping 

Process Summary Report, Prairie Island Nuclear Generating Station, Units 1 and 2, ADAMS 

Nos. ML090270154 and ML090270418.

NRC (U.S. Nuclear Regulatory Commission). 2009a. Summary of site audit related to the review 

of the license renewal application for Prairie Island Nuclear Generating Plant, Units 1 and 2, 

ADAMS No. ML083440479.

PIIC (Prairie Island Indian Community). 2008, Information provided by the Prairie Island Indian 

Community (PIIC) to aid NRC staff in the preparation of the Supplemental EIS (SEIS). PIIC 

Supplemental Information. Non-public reference per 36 CFR 800.11(c).

2-1

2.0 AFFECTED ENVIRONMENT

Prairie Island Nuclear Generating Plant (PINGP 1 and 2) is located on the west bank of 

the Mississippi River in Goodhue County within the city limits of Red Wing, Minnesota 

(Figure 2-1). The City of Hastings is located approximately 13 mi (21 km) northwest 

(upstream) of the plant. Minneapolis and St. Paul are located approximately 39 mi (63 

km) and 32 mi (51 km), respectively, to the northwest of the plant. For purposes of the 

evaluation in this report, the “affected environment” is the environment that currently 

exists at and around PINGP 1 and 2. Because existing conditions are at least partially 

the result of past construction and operation at the plant, the impacts of these past and 

ongoing actions and how they have shaped the environment are presented here. 

Section 2.1 of this report describes the facility and its operation, and Section 2.2 

discusses the affected environment.

2.1 Facility Description

This assessment of the affected environment begins with a description of PINGP 1 and 

2, the source of potential environmental effects. PINGP is a two-unit pressurized water 

reactor (PWR) plant that utilizes a hybrid cooling system, which consists of three modes 

of operation: open cycle (once-through cooling, with no cooling towers in operation), 

helper cycle (once-through cooling, with mechanical draft cooling towers in operation), 

and closed cycle (using cooling towers to recirculate up to 95 percent of the cooling 

water). The plant is licensed to operate at 1650 megawatt-thermal (MWt) per unit, or 

575 megawatts-electrical (MWe) of gross electrical output per unit.

The major structures on the PINGP 1 and 2 site include the Unit 1 and Unit 2 

containment buildings, which contain the nuclear steam supply systems including the 

reactors, steam generators, reactor coolant pumps and other related equipment; the 

turbine building, which houses the turbine generators, main condensers, and turbine 

plant heat exchangers; and the auxiliary building which houses major components of the 

primary component cooling water system, boric acid storage tanks and pumps, and

other safety-related equipment. Other structures on the plant site include the intake and 

plant screenhouses, intake and discharge canals, Independent Spent Fuel Storage 

Installation, four mechanical draft cooling towers and the PINGP substation. Figure 2-2 

provides a general layout of the PINGP 1 and 2 site.

PINGP 1 and 2 used (or spent) fuel is stored in a pool inside the plant until it is cooled, 

and transferred to dry storage containers located on site, called the Independent Spent 

Fuel Storage Installation (ISFSI). Spent fuel will be stored there until the federal 

government removes it to be reprocessed or stored at a government facility. As of early

2010, Prairie Island’s ISFSI housed 26 dry-storage containers, which hold a store of 

1040 spent fuel assemblies ( NSPM 2010).

2.1.1 Reactor and Containment Systems

PINGP is a two-unit plant with Westinghouse Electric Company PWRs. PINGP 1 and 2 

received its construction permit on June 25, 1968. Full commercial operation began on 

December 16, 1973, for Unit 1 and December 21, 1974, for Unit 2 (NMC 2008).

The reactor fuel consists of uranium-dioxide pellets that have been enriched to less than 

5.0 percent by weight with uranium-235 and enclosed in Zircaloy tubes. Each reactor 

core consists of 121 fuel assemblies and 29 moveable control rod assemblies (NMC 
Affected Environment

2-2

By design, the operation 

of nuclear power plants is 

expected to result in small 

releases of radiological 

effluents (gaseous, liquid, 

and solid) through 

controlled processes. 

However, releases must 

meet stringent NRC and 

EPA regulatory limits. 

2008). Control rods consist of stainless steel absorber rods and Zircaloy guide tubes 

and are used for short-term reactivity control associated with changes in power level and 

with changes in fuel burnup between adjustments in reactor coolant dissolved boron 

concentrations (AEC 1973). Each unit is designed to generate 1650 Mega-watts 

thermal (MWt) with a maximum power output of 1721.4 MWt. (NMC 2008).In a PWR 

power generation system, reactor heat is transferred from the primary coolant to a lower 

pressure secondary coolant loop, allowing steam to be generated in the steam supply 

system. At PINGP 1 and 2, each unit consists of two primary coolant loops. With each 

loop containing one steam generator, one centrifugal coolant pump, and the 

interconnected piping. Reactor coolant is pumped from the reactor through the steam 

generators and back to the reactor via vertical, single-stage, centrifugal pumps. Each 

steam generator is a vertical U-tube unit that produces steam at a constant pressure 

over the reactor operating power range. Coolant flows through the tubes, and steam is 

generated on the lower pressure shell side. Steam then flows from the steam generator 

to the tandem-compound, three-element 1800-rpm turbine generator (AEC 1973). 

The NRC is aware that the NSP is planning to submit an amendment request to increase 

the reactor core thermal power level by approximately 10 percent over what is currently 

licensed. This change in power level requires NRC review and approval prior to its 

implementation. When NSP submits the amendment request, they must also submit an 

environmental report that describes the environmental impacts of the requested action.

As part of the NRC’s license amendment process, the staff will perform a thorough 

evaluation of the safety, radiological, and environmental issues associated with the 

proposed power increase to verify that that all regulatory requirements are met.

2.1.2 Radioactive Waste Management

PINGP 1 and 2’s radioactive waste disposal systems are 

designed to collect, treat, and dispose of the radioactive and 

potentially radioactive wastes that are byproducts of plant 

operations. Byproducts include: activation products resulting 

from the irradiation of reactor water and impurities therein 

(principally metallic corrosion products) and fission products 

resulting from defective fuel cladding or uranium contamination 

within the reactor coolant system. Operating procedures for 

radioactive waste disposal systems ensure that the radioactive 

wastes are safely processed and discharged from the plant in 

manners that meet the release limits as set forth in 10 CFR Part 20, “Radiation 

Protection Standards;” 10 CFR Part 50, “Domestic Licensing of Production and 

Utilization Facilities;” the plant’s technical specifications; and the PINGP 1 and 2 Offsite 

Dose Calculation Manual (NMC 2007b).

Radioactive wastes resulting from plant operations are classified as liquid, gaseous, or 

solid. Liquid radioactive wastes are generated from liquids received directly from 

portions of the reactor coolant system or were contaminated by contact with liquids from 

the reactor coolant system. Gaseous radioactive wastes are generated from gases or 

airborne particulates vented from reactor and turbine equipment containing radioactive 

material. Solid radioactive wastes are solids from the reactor coolant system, solids that 

have come into contact with reactor coolant system liquids or gases, or solids used in 

the reactor coolant system or steam and power conversion system operation or 

maintenance.
Affected Environment

2-3

Reactor fuel that has exhausted a certain percentage of its fissile uranium content is 

referred to as spent fuel. Spent fuel assemblies are removed from the reactor core and 

replaced with fresh fuel assemblies during routine refueling outages, typically every 18 to 

24 months (NMC 2008). Spent fuel assemblies are then stored for a period of time in the 

spent fuel pool and later transferred to the PINGP 1 and 2 Independent Spent Fuel 

Storage Installation. (ISFSI; NMC 2008)

PINGP 1 and 2’s Offsite Dose Calculation Manual contains the methodology and 

parameters used to calculate offsite doses resulting from radioactive gaseous and liquid 

effluents, and the gaseous and liquid effluent monitoring alarm and trip set points used 

to verify that the radioactive material being discharged meets regulatory limits (NMC 

2007b). The Offsite Dose Calculation Manual also contains the radioactive effluent 

controls and radiological environmental monitoring activities and descriptions of the 

information that should be included in the annual Radiological Environmental Monitoring

Report and annual Radioactive Effluent Release Report required by Appendix I, 

“Numerical Guides for Design Objectives and Limiting Conditions for Operation to Meet

the Criterion ‘As Low as is Reasonably Achievable’ (ALARA) for Radioactive Material in 

Light-Water-Cooled Nuclear Power Reactor Effluents,” to 10 CFR Part 50, and 10 CFR 

50.36a, “Technical Specifications on Effluents from Nuclear Power Reactors,”

respectively.

2.1.2.1 Radioactive Liquid Waste

The PINGP 1 and 2’s liquid radioactive waste processing system, in combination with 

the steam generator blowdown system, collects, holds, treats, processes, and monitors 

all liquid radioactive wastes for reuse or disposal. The PINGP 1 and 2 liquid radioactive 

waste processing system segregates various stream wastes at the point of their 

collection into the following categories: non-aerated and aerated wastes, chemical 

drains, steam generator blowdown and resin waste. 
Affected Environment

2-4

Figure 2-1. Location of Prairie Island Nuclear 

Generating Plant, Units 1 and 2, 50-mi (80-km) 

Region (Source: NMC 2008)
Affected Environment

2-5

Figure 2-2. PINGP 1 and 2 General Site Layout 

and Exclusion Area Boundary

(Source: NMC 2008)
Affected Environment

2-6

Liquid wastes are collected in sumps and drain tanks and transferred to the appropriate 

subsystem collection tanks for subsequent treatment, disposal, or recycling. Nonaerated waste is originated primarily by the reactor coolant system, which is transferred 

to the holdup tanks for processing after collection. Aerated waste originates primarily 

from the floor drains, aerated equipment drains and leaks, laundry equipment drains and 

decontamination area drains and is transferred to aerated drains treatment tanks for 

monitoring and final release or reprocessing. Chemical drains from the hot sampling 

station and hot chemical laboratory are collected in the chemical drain tank, periodically 

neutralized (if needed), transferred to the aerated sump tank and finally transferred to 

the aerated drains treatment collection tanks for processing through the aerated drains 

treatment cartridge filters and three flushable ion-exchangers, which are shared by 

PINGP 1 and 2, and final discharge. PINGP 1 and 2 steam generators blowdown waste 

is discharged into a flash tank in the associated unit, transferred to the holdup tanks and 

directed to the condenser through the system of a filter and ion exchanger under normal 

operation conditions. Occasionally (such as during startup) the blowdown used to 

control steam generator chemistry is released to the circulating water canal via a 

radiation monitor. Liquid releases from the steam generator blowdown monitor tank are 

made based on the results of a radiochemical batch analysis of the tank contents and 

are monitored by the waste disposal system liquid effluent monitor. Resin waste is 

collected from the resin disposal building sump in the drains collection tanks or the 

waste holdup tank. Waste water from the truck loading enclosure sump is pumped to 

the aerated sump tank and further processed by the liquid radioactive waste processing 

system. The PINGP 1 and 2 liquid radwaste discharge point and steam generator 

blowdown was extended from the original discharge point at the head of the circulating 

water discharge canal to just upstream of the circulating water canal discharge structure 

at the Mississippi River in order to minimize the potential for the tritium to enter the local 

ground water. Liquid releases are limited to the maximum extent possible to satisfy the 

design objectives of Appendix I to 10 CFR Part 50. Liquid discharges occur when the 

radioactive material has been analyzed and the projected dose to members of the public 

has been calculated to be within the values specified in the Offsite Dose Calculation 

Manual, 10 CFR 20, and Appendix I to 10 CFR 50. (NMC 2008)

The U.S. Nuclear Regulatory Commission (NRC) staff reviewed the PINGP 1 and 2 

radioactive effluent release reports for 2003 through 2007 for liquid effluents (NMC 

2004a, 2005a, 2006b, 2007c, 2008b). The releases in 2007 were representative of the 

releases in prior years. Variations in the amount of radioactive effluents released from 

year to year are expected based on the overall performance of the plant and the number 

and scope of outages. The liquid radioactive wastes reported by PINGP 1 and 2 are 

reasonable and no unusual trends were noted. These releases would result in minimal 

doses to members of the public that are well below the ALARA dose design objectives of 

Appendix I to 10 CFR 50, as discussed in Section 4.8.1.

Northern States Power Co. (NSP) is planning to replace the Unit 2 steam generators 

prior to the period of extended operation. Such an action is not likely to result in a 

significant increase of liquid radioactive effluents being discharged as compared to the 

amount discharged during normal plant operations. This is based on consideration that 

any liquids generated, processed, and released during the outage will be offset by the 

amount of liquid waste that would not be generated, processed, and released during 

normal plant operations. Based on the historical evaluation and there being no 

significant increase in liquid effluents from the replacement of the PINGP Unit 1 steam 

generators, similar quantities of radioactive liquid effluents are expected to be generated 
Affected Environment

2-7

during normal operations and outages from PINGP 1 and 2 during the period of 

extended operation.

2.1.2.2 Radioactive Gaseous Waste

The gaseous radioactive waste processing system and the plant ventilation exhaust 

system control, collect, process, store, and dispose of gaseous radioactive wastes 

generated as a result of normal operation. Gaseous effluents are treated before release 

to the environment. PINGP 1 and 2’s gaseous radioactive waste processing system

consists of two interconnected process loops: the low level and the high level loops.

PINGP 1 and 2’s gaseous radioactive waste processing system receives radioactive 

gases mainly from the four sources: displacement of cover gases as liquids accumulate 

in various tanks, miscellaneous equipment vents and relief tanks, automatic gas analysis 

and sampling for hydrogen and oxygen in cover gases and nitrogen stripping of reactor 

coolant to remove hydrogen during shutdown operations. The low-level loop is designed 

to accumulate, contain and process cover gases from all these sources. During normal 

operating conditions the gas flow is split through the hydrogen recombiner to the decay 

tanks. The system is vented into the atmosphere and results in an occasional discharge 

only in case of the disposal of the gases collected from shutdown operations and from 

miscellaneous vents. Prior to discharge the low-level decay tank content is sampled and 

analyzed to record gas activity, and discharged to the auxiliary building vent at a 

controlled rate. The high-level loop is designed to collect, hold and process high-activity 

gases received during reactor coolant hydrogen stripping that allows removing of the 

fission gases. The high-level loop is normally not used because the activity level of the 

reactor coolant fission gas is usually low. The high-level loop gas decay tanks are used 

for the low-level loop reserve holding capacity, which minimizes the frequency of gas 

decay tank releases. PINGP 1 and 2 maintains radioactive gaseous effluents in

accordance with the procedures and methodology described in the Offsite Dose 

Calculation Manual. The gaseous radioactive waste processing system is used to 

reduce radioactive materials in gaseous effluents before discharge to meet the ALARA 

dose objectives in Appendix I to10 CFR Part 50. (NMC 2007b)

The NRC staff reviewed the PINGP 1 and 2 radioactive effluent release reports for 2003 

through 2007 for gaseous effluents (NMC 2004a; 2005a; 2006b; 2007c; 2008b). The 

gaseous discharges for 2007 are consistent with the radioactive gaseous effluents 

discharged from 2003 through 2006. Based on the gaseous waste processing systems 

and effluent controls and performance from 2003 through 2007, similar small quantities 

of radioactive gaseous effluents are expected from PINGP 1 and 2 and are not expected 

change significantly during the period of extended operation. These releases would 

result in doses to members of the public that are well below the ALARA dose design 

objectives. Section 4.8.1 provides a discussion of the calculated doses to the maximally 

exposed individual as a result of these releases.

NSP is planning to replace the Unit 2 steam generators prior to the period of extended 

operation. Such an action is not likely to result in a significant increase of gaseous 

radioactive effluents being discharged as compared to the amount discharged during 

normal plant operations. This is based on consideration that any gaseous effluents 

released during the outage will be offset by the amount of gaseous effluents that would 

not be generated, processed, and released during normal plant operations. Based on 

the historical evaluation and there being no significant increase in gaseous effluents 

from the replacement of the PINGP Unit 1 steam generators, similar quantities of 
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radioactive gaseous effluents are expected to be generated during normal operations 

and outages from PINGP 1 and 2 during the period of extended operation.

2.1.2.3 Solid Radioactive Waste

The solid radioactive waste management system at PINGP 1 and 2 is designed to 

collect, package, provide shielded storage facilities and to allow temporary storage prior 

to offsite shipment for processing or disposal of low-level radioactive wastes generated 

as a result of normal plant operation. The system is designed to maintain ALARA

radiation exposure to plant personnel in accordance with General Design Criterion 60 of 

the Appendix A to 10 CFR Part 50 and Regulatory Guide 8.8. This system maintains 

personnel exposures below 10 CFR Part 20 requirements. The solid radioactive waste 

management system equipment is located in the radioactive waste processing facility 

and the dry active waste facility. The dry active waste facility is also capable of storing 

the packaged waste until it is shipped offsite to a waste processor for treatment/disposal 

or to the licensed burial sites. Transportation and disposal of solid radioactive wastes 

are performed in accordance with the applicable requirements of 10 CFR Part 71 and 10 

CFR Part 61, respectively. Access to the process equipment and solid radioactive waste 

storage areas is controlled to minimize personnel exposure by suitable barriers such as 

locked doors, gates, or control cards.

Low-level mixed waste is waste that exhibits hazardous characteristics and contains low 

levels of radioactivity. PINGP does not normally produce any low-level mixed waste. 

PINGP 1 and 2 solid wastes are comprised mainly of dry active waste such as 

contaminated paper, plastic, wood, metals and spent resin that can be compacted for 

offsite disposal or stored onsite. PINGP 1 and 2’s solid radioactive waste management 

system operations include dewatering and pH adjustment of beaded resins, and 

powdered resins. Contaminated metals are collected for offsite disposal (or may be 

stored onsite if the disposal site is not available). Spent resins are received, dewatered 

and handled in the disposal building, next to the radwaste building (NMC 2008).

The NRC staff reviewed PINGP 1 and 2 solid radioactive waste reports for 2003 through 

2007 (NMC 2004b; 2005b; 2006c; 2007d; 2008c). Based on the performance from 2003 

through 2007, similar quantities of radioactive solid wastes are expected from PINGP 1 

and 2 during the period of extended operation. Variations on the amount of solid 

radioactive waste generated and shipped from year to year are expected based on the 

overall performance of the plant and the number and scope of maintenance work and 

outages. The volume and activity of solid radioactive waste reported by PINGP 1 and 2 

are reasonable and no unusual trends were noted.

NSP is planning to replace the Unit 2 steam generators prior to the period of extended 

operation. Such an action is likely to result in a small increase in the amount of solid 

radioactive waste generated. During an outage of this type, there will be an increased 

use of protective clothing, safety equipment, increased use of filters, and a general 

increase in generation of debris that will have to be disposed of as radioactive waste. 

However, the increased volume is expected to be within the range of solid waste that 

can be safely handled by PINGP 1 and 2 during the period of extended operation.

2.1.3 Nonradiological Wastes

Section 2.3.7.3 of the GEIS states, “The nonradioactive waste generated at nuclear 

power plants is generally not of concern unless it is classified as Resource Conservation 

and Recovery Act (RCRA) waste. All waste that is hazardous, that is, classified as 
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RCRA waste, is packaged and disposed of in a licensed landfill consistent with the 

provisions of RCRA.” RCRA governs the disposal of solid and hazardous wastes, and its 

regulations are contained in Title 40, “Protection of the Environment,” Parts 239 through 

299 (40 CFR 239, et seq.), of the Code of Federal Regulations. Parts 239 through 259 

of Title 40 contain regulations for solid (nonhazardous) waste, and Parts 260 through 

279 contain regulations for hazardous waste. RCRA Subtitle C establishes a system for 

controlling hazardous waste from “cradle-to-grave,” and RCRA Subtitle D encourages 

States to develop comprehensive plans to manage nonhazardous solid waste and 

mandates minimum technological standards for municipal solid waste landfills (EPA 

2007). In Minnesota, RCRA regulations are administered by the Minnesota Pollution 

Control Agency (MPCA). MPCA addresses the identification, generation, minimization, 

transportation, and final treatment, storage, or disposal of hazardous and nonhazardous 

wastes. PINGP 1 and 2 generate nonradioactive waste from routine plant maintenance, 

cleaning, and operational processes—most of this waste consists of nonhazardous 

waste oil, oil-filled equipment, and oily debris (NMC 2008).

2.1.3.1 Hazardous Waste

Hazardous waste means solid waste, or a combination of solid wastes, which, because 

of its quantity, concentration, or physical, chemical, or infectious characteristics, may 

cause or contribute to an increase in mortality or serious illness. Such waste may also 

pose a significant present or potential hazard to human health or the environment if it is 

not properly treated, stored, transported, disposed of, or otherwise handled (40 CFR 

Part 261, “Identification and Listing of Hazardous Waste”). PINGP 1 and 2 generate a 

small quantity of hazardous waste including spent and expired chemicals, laboratory 

chemical wastes, Freon-contaminated oil, and occasional project-specific wastes (NMC 

2008). 

The PINGP 1 and 2 site is classified as a Small Quantity Generator of hazardous waste 

because the site generates less than 1,000 kilograms (kg) (2,205 pounds (lbs)) of 

hazardous waste in one month, and no more than 6,000 kg (13,228 lbs) of hazardous 

waste may be accumulated on site at any one time (EPA 2007a). According to the U.S. 

Environmental Protection Agency (EPA) Envirofacts Warehouse online database, the 

PINGP 1 and 2 site is classified as an active Small Quantity Generator of hazardous 

wastes (EPA ID No. MND049537780). The Envirofacts Warehouse database showed 

no violations for PINGP 1 and 2 (EPA 2009). In accordance with the Minnesota 

hazardous waste generator re-licensing process (Minnesota Administrative Rules, part 

7045.0248), PINGP 1 and 2 submit annual reports to MPCA detailing the amounts and 

types of hazardous wastes generated at the plant. A review of hazardous waste license 

applications submitted by Xcel Energy to MPCA revealed that through 2003 through 

2007, PINGP 1 and 2 generated approximately 12,575 kg (27,724 lbs) of hazardous 

waste. The majority of this was paint-related waste, hazardous metals, and corrosive 

liquids.

The Emergency Planning and Community Right-to-Know Act (EPCRA) requires 

applicable facilities to provide information on hazardous and toxic chemicals to local 

emergency planning authorities and the EPA. On October 17, 2008, EPA finalized 

several changes to the Emergency Planning Notification (Section 302), Emergency 

Release Notification (Section 304), and Hazardous Chemical Storage Reporting 

Requirements (Sections 311 and 312) regulations (73 FR 65452). PINGP 1 and 2 are

subject to Federal EPCRA reporting requirements, and thus submit annual Emergency 

and Hazardous Chemical Inventory Forms to the Minnesota Emergency Response 

Commission, pursuant to Section 312.
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2.1.3.2 Universal Waste

Universal waste is hazardous waste that is generated in a variety of settings by a vast 

community, which poses collection and management problems. EPA classifies several 

hazardous wastes as universal wastes—including batteries, certain pesticides, mercurycontaining devices, and fluorescent lamps (40 CFR Part 273, “Standards for Universal 

Waste Management”). Minnesota has incorporated EPA’s regulations regarding 

universal wastes in Minnesota Administrative Rules part 7045.1400, “Adoption of 

Federal Standards for Universal Waste Management.” MPCA defines lighting ballasts, 

polychlorinated biphenyl (PCB) small capacitors, mercury containing devices, batteries, 

antifreeze, circuit boards, electronics, photographic negatives, cathode ray tubes, 

alkaline batteries, and non-TCLP (toxic characteristic leaching procedure) fluorescent 

and HID (high intensity discharge) lamps as universal waste. PINGP 1 and 2 are

classified as a Small Quantity Generator of universal waste, accumulating less than 

5,000 kg (11,023 lbs) of universal waste per month (NMC 2008).

2.1.3.3 Permitted Discharges

PINGP 1 and 2 generate two types of wastewater: industrial effluents and sanitary liquid

wastes. Industrial effluents, including cooling water, are discharged to the Mississippi 

River according to the facility’s individual wastewater discharge NPDES permit (No. 

MD0004006), as enforced by MPCA (MPCA 2006). Normal operating processes used 

to control the pH of reactor coolant, prevent scale and erosion in the cooling system, and 

clean and defoul the condenser of biological organisms, all generate chemical and 

biocide wastes. Waste liquids from these processes are combined with cooling water 

and are discharged to the Mississippi River according to the NPDES permit limitations. 

Sanitary liquid wastes are directed to eight onsite septic systems. Section 2.1.7.3 of this 

report provides more information on the PINGP 1 and 2 NPDES permit and effluent 

limitations, and radioactive liquid waste is addressed in Section 2.1.2.1.

2.1.3.4 Pollution Prevention and Waste Minimization

Under NSP’s (formerly Xcel Energy’s) Waste Management Program Procedure/Waste 

Management Guidance Manual, PINGP 1 and 2 implement a waste minimization 

program that consists of steps such as segregating hazardous and nonhazardous 

wastes, choosing nonhazardous substitutes when possible, recycling or reclaiming 

appropriate waste materials, monitoring expired chemicals to determine minimum 

stocking requirements to reduce recurring excess, finding alternate uses for excess 

materials, or returning unused materials to the manufacturer. The manual also provides 

guidelines for proper handling, storage, transport, and disposal of hazardous materials 

(NMC 2008). NRC staff determined at the site audit in August of 2008 that common 

waste materials such as paper, plastic, or aluminum are recycled at PINGP 1 and 2. 

In support of nonradioactive waste minimization efforts, the EPA Office of Pollution 

Prevention and Toxics established a clearinghouse that provides information regarding 

waste management and technical and operational approaches to pollution prevention. 

The EPA clearinghouse can be used as a source for additional opportunities for waste 

minimization and pollution prevention at PINGP 1 and 2, as appropriate (EPA 2007).

2.1.4 Plant Operation and Maintenance

Maintenance activities conducted at PINGP 1 and 2 include inspection, testing, and 

surveillance to maintain the current licensing basis of the facility and to ensure 

compliance with environmental and safety requirements. Various programs and 
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activities currently exist at PINGP 1 and 2 to maintain, inspect, test, and monitor the 

performance of facility equipment. These maintenance activities include inspection 

requirements for reactor vessel materials, boiler and pressure vessel in-service 

inspection and testing, a maintenance structures monitoring program, and maintenance 

of water chemistry.

Additional programs include those implemented to meet technical specification 

surveillance requirements, those implemented in response to the NRC generic 

communications, and various periodic maintenance, testing, and inspection procedures. 

Certain program activities are performed during the operation of the unit, while others 

are performed during scheduled refueling outages. Nuclear power plants must 

periodically discontinue the production of electricity for refueling, periodic in-service 

inspection, and scheduled maintenance. PINGP 1 and 2 refuel on at 20-month interval.

2.1.5 Power Transmission System

The PINGP 1 and 2 substations, located on the PINGP 1 and 2 site just north of the 

generating facilities, provides connections for four 345-kV lines, owned by NSP and 

maintained by Xcel Energy, and one 161-kV line, owned and maintained by Great River 

Energy (Figure 2-3). Unless otherwise noted, the discussion of the power transmission 

system is adapted from the ER (NMC 2008), or information gathered during NRC’s site 

audit.

NSP constructed approximately 78 mi (126 km) of new transmission lines to support the 

operation of PINGP 1 and 2 and acquired 32.8 mi (528 km) of new right-of-way (ROW) 

land for these newly constructed lines (AEC 1973). In total, the transmission lines 

associated with the operation of PINGP 1 and 2 comprise approximately 2300 ac (930 

ha) of ROW land.

Transmission lines considered in scope for license renewal are those constructed 

specifically to connect the facility to the transmission system (10 CFR 51.53(c)(3)(ii)(H)); 

therefore, the Red Rock 1 connection, the Adams connection, the Red Rock 2 line, the 

Blue Lake Line, and the Spring Creek line are considered in-scope for this supplemental 

environmental impact statement (SEIS) and are discussed below in detail. These 

transmission lines span Goodhue, Dakota, Scott, and Washington Counties (Figure 2-4).

The Red Rock 1 connection and the Adams connection split a previously existing 

transmission line, the 345-kV Red Rock-Adams line, in order to connect the line to the 

PINGP 1 and 2 substation. Because the Red Rock-Adams line was constructed and put 

into service before the construction of PINGP 1 and 2, only the two portions constructed 

to connect this line to the PINGP 1 and 2 substation are considered in-scope for 

purposes of this analysis. Each connection is 345 kV and 2.5 mi (4.0 km) in length. The 

connections are contained within Goodhue County and share a 250-ft (76-m)-wide ROW 

with the Red Rock 2 and Blue Lake lines.

The 345-kV Red Rock 2 line runs northwest for approximately 32 mi (52 km) to the Red 

Rock substation in St. Paul, Minnesota. The line spans Goodhue, Dakota, and 

Washington Counties. The Red Rock 2 line shares a 250-ft (76-m)-wide ROW with the 

Red Rock-Adams transmission line connections and the Blue Lake line for the first 2.5 

mi (4.0 km) and shares a 350-ft (107-m)-wide ROW with the Red Rock 1 line for the 

remaining length. Construction of this line did not require the creation of any additional 

ROWs because the entire length of the line was routed along an existing ROW.
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The 345-kV Blue Lake line runs west for approximately 50 mi (80 km) to the Scott 

County substation. The line spans Goodhue, Dakota, and Scott Counties. The Blue 

Lake line shares a 250-ft (76-m)-wide ROW with the Red Rock-Adams transmission line 

connections and the Red Rock 2 line for the first 2.5 mi (4.0 km) and has a 150-ft (46-

m)-wide ROW for the remaining length. The first segment of this line required the 

creation of a new ROW from PINGP 1 and 2 to the Inver Grove substation in Dakota 

County, Minnesota; the remaining length to the Blue Lake substation was routed along 

an existing ROW.

The 161-kV Spring Creek line runs south for approximately 5 mi (8 km) to the Spring 

Creek substation near Red Wing, Minnesota. The line is contained within Goodhue 

County and has a 100-ft (30 m)-wide ROW.

Xcel Energy and Great River Energy maintain transmission line ROWs to promote lowgrowing grasses and non-woody vegetation directly under towers and conductors. ROW 

borders are maintained to promote slow-growing shrubs and shorter trees that do not 

interfere with transmission lines or structures. Woody vegetation within ROWs may be 

pruned, chemically controlled, or removed to ensure adequate line clearance; however, 

neither Xcel Energy nor Great River Energy disturb or remove trees and shrubs unless 

they have the potential to interfere with transmission facilities. The majority of ROWs 

associated with PINGP 1 and 2 consist of grasslands or agricultural land, which require 

minimal maintenance. Herbicides, when necessary, are applied by licensed certified 

applicators in full compliance with the Minnesota Pesticide Control Law of 1987. All 

herbicides used near waterways or in wetland areas are EPA-approved for aquatic 

application. Xcel Energy does not spray herbicides on foliage at heights above 10 ft (3 

m), which minimizes the risk of drift to wetlands and waterways. For herbicides that are 

not approved for aquatic use, Great River Energy requires a non-treated buffer zone of 

25 to 50 ft (7.6 to 15.2 m) between the treated areas and any waterways.
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Figure 2-3. PINGP 1 and 2 Substation and 

Transmission Line Layout (Source: NMC 2008)
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Figure 2-4. PINGP 1 and 2 Transmission 

System (Source: NMC 2008)
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2-15

Both Xcel Energy and Great River Energy perform regular flyovers to identify areas that 

require maintenance. Because much of the ROW land is privately owned agricultural 

land, Xcel Energy will avoid spraying herbicides at the owner’s request and will only 

remove trees and shrubs that are hazardous to transmission lines or structures. The 

Xcel Energy vegetative management guidelines also includes measures to ensure avian 

protection by including procedures workers must follow when tree crews encounter 

active and/or inactive nests and dead or injured birds.

All transmission lines will remain a permanent part of the transmission system and will 

be maintained by Xcel Energy and Great River Energy, regardless of PINGP 1 and 2 

continued operation.

Table 2-1. PINGP 1 and 2 Transmission Lines. Five transmission lines convey 

electricity from PINGP 1 and 2 to the regional electric transmission system via 

three rights of way (ROWs).

Line Owner kV

Approximate 

Distance

ROW 

Width ROW Area

mi (km) ft (m) ac (ha)

Red Rock 1 connection NSP (Formerly Xcel) 345 2.5 (4.0) 250 (76) 76 (31)(a)

Red Rock 2 NSP 345 32 (52) 350 (107) 1360 (550)(a)

Blue Lake NSP 345 50 (80) 150 (46) 940 (380)(a)

Adams connection NSP 354 2.5 (4.0) 250 (76) 76 (31)(a)

Spring Creek Great River Energy 161 5 (8) 100 (30) 61 (25)

(a) ROW area values for the Red Rock 1 connection, the Adams connection, the Red Rock 2 line, and the Blue Lake line 

include 76 ac (31 ha) shared by all four lines along the first 2.5 mi (4.0 km) of ROW traveling west from PINGP 1 and 2.

Source: NMC 2008

2.1.6 Cooling and Auxiliary Water Systems

The Mississippi River is the source for cooling water for the main condenser at PINGP 1 

and 2. River water used for cooling can be circulated through the station in one of three 

modes of operation: open cycle (once-through cooling, with no cooling towers in 

operation), helper cycle (once-through cooling, with mechanical draft cooling towers in 

operation), and closed cycle (using cooling towers to recirculate up to 95 percent of the 

cooling water). The mode of operation is selected by the applicant to limit the heat 

discharged to the river to ensure compliance with the thermal limits of the NPDES permit 

No. MD0004006 (MPCA 2006; NMC 2008).

The components of the current cooling water system are the eight intake bays, the 

intake screenhouse, trash racks, traveling screens, high/low pressure wash systems, 

fish return system, bypass gates, intake canal, plant screenhouse, circulating water 

pumps, condensers, discharge basin, mechanical draft cooling towers, discharge canal, 

and distribution basin. (NMC 2008)

The Final Environmental Statement (FES) for PINGP 1 and 2 (AEC 1973) describes the 

original cooling water system. Water was withdrawn from the Mississippi River into the 

750-ft (230-m)-long intake canal, and into what is now called the plant screenhouse. 

Inside the screenhouse, the water passed through trash racks and coarse-mesh 
Affected Environment

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traveling screens to remove fish and debris before supplying the condensers. The plant 

could operate in each of the three modes described above, and so the heated effluent 

from the plant was either pumped to the cooling towers or released to the river, via an 

800-ft (240-m)-long canal.

In the early 1980s, the State of Minnesota directed PINGP 1 and 2 to modify the cooling 

system to reduce impacts to aquatic communities. This was done by installing the intake 

screenhouse, equipped with trash racks, coarse- and fine-mesh traveling screens, 

variable pressure wash systems, and a fish return system, described below (Stone and 

Webster 1983).

Water flows from the river, under a skimmer wall, into the eight intake bay openings, 

each 18.5 by 11.2 ft (5.6 by 3.4 m), of the intake screenhouse. The intake bays each 

have a trash rack, a traveling screen, and high/low pressure wash systems, and a fish 

return system. After passing through the intake screenhouse, water flows down the 

intake canal to the plant screenhouse, where four 147,000-gpm (9.3-m3

/s) circulating 

water pumps supply water to the condensers for a total flow for both units of 

approximately 588,000 gpm (37.1 m3

/s). (NMC 2008)

After leaving the condensers, the cooling water then enters the discharge basin, and 

from there the final path of the cooling water is determined by the operating mode of the 

plant. In open cycle, the cooling water flows from the discharge basin, through the 

distribution basin, into the discharge canal, ultimately returning to the Mississippi River.

In helper and closed cycles, the water is pumped from discharge basin to the cooling 

towers, and from there returns to the intake canal for recirculation (closed cycle) or flows 

through the distribution basin, into the discharge canal, and out to the Mississippi River 

(helper cycle). A small amount of warm water from the discharge canal is pumped to 

the intake structure to prevent ice formation on trash racks, traveling screens, and 

bypass gates. (NMC 2008)

2.1.6.1 Intake Screenhouse and Fish Return 

Within the intake screenhouse are the trash racks and traveling screens. The trash rack 

in each bay is made of 3/8 in. by 3 in. (0.95 cm by 7.6 cm) steel bars, mounted on an 

incline 1.5 in. (3.8 cm) apart; a trash rake clears accumulated debris (NMC 20008; Stone 

and Webster 1983).

After passing through the trash rack, the water flows through the traveling screens. The 

NPDES permit No. MD0004006, issued June 30, 2006, by the MPCA, dictates that from 

September 1 through March 31, PINGP 1 and 2 may operate with up to 3/8 in. (0.95 cm) 

mesh traveling screens, and that from April 1 through August 31, the traveling screens 

must be 0.5 mm (0.02 in.) fine mesh screens (MPCA 2006). Before the cooling water 

system was modified in 1983, the approach velocity to the existing traveling screens was 

1.3 fps (0.40 m/s) at normal water levels and 1.4 fps (0.43 m/s) at low water levels. The 

design criteria for the average face velocity through the gross area of the screen material 

for the fine mesh screens should not exceed 0.5 fps (0.15 m/s) at low water level and a 

discharge rate of 800 cfs (22.6 m3

/s). Flow measurements taken in 1983 and 1984 were 

less than 0.66 fps (0.2 m/s), and most were below 0.33 fps (0.1 m/s). Intake velocities 

were again studied in 2003, during coarse mesh screen operation, and the results of that 

study are shown in Table 2-2. Based on this data, the authors of the study concluded 

that the intake velocities are not outside the design requirements. (Xcel Energy 

Environmental Services 2006).
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Table 2-2. Post-modification Velocity Profiles for the PINGP 1 and 2

Cooling Water Intake System

Blowdown in 

cfs (m3/s)

River Level in 

ft (m)

Average Velocity at Center of Bays 

in fps (m/s)

Average 

Velocity Across 

All Bays in fps 

(m/s) Maximum Minimum

1006 (28) 674.6 (205.6) 0.388 (0.118) 0.599 (0.183) 0.481 (0.147)

815 (23) 674.6 (205.6) 0.337 (0.103) 0.427 (0.130) 0.362 (0.110)

Blowdown in 

cfs (m3/s)

River Level in 

ft (m)

Average Calculated ThroughScreen Velocity (Coarse Mesh) in 

fps (m/s)

Average 

Velocity Across 

All Bays in fps 

(m/s) Maximum Minimum

1006 (28) 674.6 (205.6) 0.807 (0.246) 1.246 (0.380) 1.00 (0.305)

815 (23) 674.6 (205.6) 0.701 (0.214) 0.888 (0.271) 0.752 (0.229)

Blowdown in 

cfs (m3/s)

River Level in 

ft (m)

Average Calculated ThroughScreen Velocity (Fine Mesh) in fps 

(m/s)

Average 

Velocity Across 

All Bays in fps 

(m/s) Maximum Minimum

1006 (28) 674.6 (205.6) 0.899 (0.274) 1.388 (0.423) 1.114 (0.340)

815 (23) 674.6 (205.6) 0.781 (0.238) 0.989 (0.301) 0.838 (0.255)

Source: adapted from Xcel Energy Environmental Services 2006

To remove larvae and fish from the upward travel side of the screen, a low pressure 

spray is used, at 10 psi (0.7 kg/cm2

) from the inside for the fine mesh screen (larval 

screenwash), and at 20 (1.4 kg/cm2

) psi from the outside when the coarse mesh screen 

is in use (fish screenwash) (Stone and Webster 1983; NMC 2008). On the downward 

travel side of the screen, a high pressure spray from the inside is used to remove debris 

from the screens, at 50 psi (3.5 kg/cm2

) for the fine mesh screen and 100 psi (7 kg/cm2) 

for the coarse mesh screen (NMC 2008). The fine mesh screens rotate continuously 

between 3 and 20 fpm (1 and 6 m/min), based on the amount of debris collected; the 

coarse mesh screens rotate at the same range of speeds when the screen differential is 

higher than 4 in. (10 cm) or if the screens have not rotated for 8 hours (Xcel Energy 

Environmental Services 2006; NMC 2008).

Fish are washed off the upward travel side of the screens into a trough and debris is 

washed from the downward travel side into a separate trough. The troughs combine into 

a common trough and are transported back to the river via a 2200-ft-(670-m)-long, 

buried pipe, which discharges into the river 1500 ft (460 m) south of the Intake 

Screenhouse, below mean water elevation, and at a depth below any ice cover. Fish 

and debris travel through the pipe at velocities between 3 to 5 ft/s (1 to 1.5 m/s), but may 

speed up in sections of the pipe. (Stone and Webster 1983; Xcel Energy Environmental 

Services 2006; NMC 2008).
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If the screens are clogged, the head differential across the traveling screens or across 

the intake screenhouse can become too high, triggering bypass gates to open allowing

water to circumvent the intake screenhouse. The plant screenhouse (part of the original 

cooling system) is still equipped with 3/8 in. screens that remove debris before the water 

enters the condensers, and the intake screens are cleared to minimize the time the 

bypass gates are open. (Stone and Webster 1983).

2.1.6.2 Discharge and Cooling Tower System 

The discharge basin receives all of the cooling water from the condensers. The path 

that the water takes next is dependent on the operating mode of the cooling system. 

During open cycle, the water flows through the distribution basin, into the discharge 

canal, and out to the Mississippi River. During closed and helper cycles, the water is 

pumped to the cooling towers. The cooled water is then routed via the cooling tower 

return canal to the distribution basin. In closed cycle, the distribution basin returns the 

water to the intake canal to recycle through the condensers. In helper cycle, the 

distribution basin routes the water to the discharge canal to be discharged into the river. 

(NMC 2008)

Water enters the discharge canal through four 10 by 11 ft (3 by 3.4 m) openings to four 

sluice gates which are operated by motors. The sluice gates lead to four pipes, which 

vary in diameter [5, 6, 7, and 8 ft (1.5, 1.8, 2.1, and 2.4 m)] and are used in different 

combinations to achieve the desired discharge rate. If only the smallest pipe is in use, 

the discharge rate is 150 cfs (4 m3

/s). If all four pipes are used (all sluice gates are 

open), the maximum discharge rate is 1390 cfs (39 m3

/s), and the velocity of the 

discharging water is 10.17 ft/s (3.1 m/s). (Stone and Webster 1983)

The mechanical draft cooling tower system includes four cooling towers, fans, water 

distribution headers, and basins. Each tower, made up of a bank of 12 sections cells, 

includes a cooling tower pump, which pumps water from the discharge basin through 

distribution pipes to the top of the cooling tower. Spray nozzles disperse the water, 

which drops through a maze of “fill” to the basin at the base of the cooling towers. Fans 

draw air up through the streams of water, evaporating water and allowing the heat to 

disperse out the top of the cooling towers into the atmosphere. The water in the cooling 

tower basin flows through the cooling tower return canal to the distribution basin, where 

it can either be routed back through the facility’s condensers by way of the intake canal 

(closed cycle) or sent to the discharge canal to return to the Mississippi River (helper 

cycle). The cooling towers can be used for the total circulating water flow of 588,000 

gpm (37.1 m3

/s) and can remove up to 96 percent of the waste heat created by the 

facility. (NMC 2008)

2.1.6.3 Requirements Under NPDES Permit 

In accordance with the Federal Water Pollution Control Act (or the Clean Water Act 

[CWA]), PINGP 1 and 2 cooling water discharges are regulated by the NPDES and State 

Disposal System Permit No. MN0004006 issued and enforced by the MPCA. Section 

402 of the CWA states that “NPDES prohibits [discharges] of pollutants from any point 

source into the nation’s waters except as allowed under an NPDES permit.” The 

purpose of this permit is to regulate wastewater discharge to preserve the water quality 

of the surrounding water bodies. As of the most recent permit issued, there have been 

no notices of violation for the PINGP 1 and 2 site. Information in this section was 

obtained from the most recent PINGP 1 and 2 NPDES permit, a copy of which is 

included in the applicant’s license renewal ER. The current NPDES was set to expire in
Affected Environment

2-19

August 2010. In the spring of 2010, NSP submitted a timely permit application to MPCA 

to renew the NPDES permit. NSP’s current NPDES will remain in effect until MPCA 

issues a renewed permit. As of April 2011, MPCA had not issued the renewed permit 

In order to minimize the impacts from the PINGP 1 and 2 cooling system on entrainment 

and impingement of fish and shellfish, the NPDES permit dictates the screen size the 

plant must use during the spring and summer (Table 2-3).

Additionally, the NPDES permit imposes limits on the discharge of cooling water from 

April to June, in order to minimize the impacts of entrainment and impingement of fish 

and shellfish (Table 2-4). This indirectly restricts the withdrawal rates, as the discharge 

rate approximates the withdrawal rate. 

To minimize the impacts of the heated discharge from the PINGP 1 and 2 cooling 

system, the NPDES permit specifies the times and trigger points when the plant must 

switch the operating mode of the cooling system (Table 2-5). The permit defines the fall 

trigger point as when the daily average upstream ambient river temperature falls below 

43 °F (6 °C) for five consecutive days. (MPCA 2006)

Table 2-3. PINGP 1 and 2 Screen Mesh Size and Spray Wash Pressure 

Requirements. Mesh size and spray wash pressure are specified by the PINGP 

1 and 2 NPDES permit and vary by time of year.

Time of Year Screen Mesh Size Spray Wash Pressure

April 1 to August 31 0.5 mm fine mesh screen Low Pressure (larval): 10 psi

High Pressure (debris): 50 psi

September 1 to March 31 3/8 in. coarse mesh screen Low Pressure (fish): 20 psi

High Pressure (debris): 100 psi

Table 2-4. PINGP 1 and 2 Plant Flow (Discharge) Restrictions. Discharge 

restrictions are implemented in the PINGP 1 and 2 NPDES permit and vary by 

time of year and river flow.

Time of Year River Flow Plant Flow (Discharge)

April 15-30

April 15-30

< 15,000 cfs (425 m3/s)

≥ 15,000 cfs (425 m3/s)

97 mgd (150 cfs; 4.25 m3/s)

194 mgd (300 cfs; 8.5 m3/s)

May n/a 194 mgd (300 cfs; 8.5 m3/s)

June 1-15

June 16-30

n/a

n/a

259 mgd (400 cfs; 11.3 m3/s)

517.5 mgd (800 cfs; 22.7 m3/s)
Affected Environment

2-20

Table 2-5. PINGP 1 and 2 Cooling Mode Requirements. Cooling mode 

requirements are specified by the PINGP 1 and 2 NPDES permit and vary by 

time of year.

Time of Year Requirements 

April 1 through Fall Trigger Operate cooling towers as necessary so that:

• Receiving water is not raised by more than 5 °F (-15 

°C) above ambient.

• Cooling water discharge does not exceed a daily 

average temperature of 86 °F (30 °C)

• If the daily average ambient temperature reaches 78 

°F (26 °C) for two consecutive days, all cooling towers 

shall be operated to maximum extent practicable

Fall Trigger through March 31 If temperature of receiving water exceeds 43 °F (6 °C) for two 

consecutive days, the MPCA and MN DNR must be notified. 

The MPCA may require the use of cooling towers or 

alternative measures to reduce water temperatures.

1 Requirements begin April 1, but can be earlier, if the daily average ambient river temperature increases to 

43 °F (6 °C) or above for five consecutive days.

2 The fall trigger point is when the daily average upstream ambient river temperature falls below 43 °F (6 °C) 

for five consecutive days. 3 Receiving water is the water immediately below Lock and Dam 3.

4 Ambient water temperatures are based on upstream monitoring and the monthly averages of maximum 

daily temperatures at three monitoring probes located at the dam.

Periodically, NSP treats the PINGP 1 and 2 cooling water system with oxidizing biocides, 

chlorine and bromine, to prevent the growth of biofouling micro-organisms. The NPDES 

permit limits the release of these biocides, as shown in Table 2-6. (MPCA 2006; NMC 

2008)

Table 2-6 shows the quantitative effluent limitations regulated under the NPDES permit, 

or the residual concentrations of permitted chemical additives that may be discharged to 

the surface waters. In accordance with this permit, if PINGP 1 and 2 introduce any new 

chemical additives in its operation, or the current dosages are increased, they must first 

be reviewed and approved by the MPCA. In addition to these effluent limitations, the 

permit includes thermal limitations and water intake restrictions. 
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2-21

Table 2-6. NPDES Effluent Limitations for PINGP 1 and 2

Outfall 

No.

Total Suspended 

Solids 

(mg/L)

Total Residual 

Bromine 

(mg/L)

Total Residual 

Chlorine 

(mg/L)

Oil and Grease 

[Hexane Extraction] 

(mg/L)

Quarterly 

Avg.

Daily 

Max.

Daily 

Max.

Instant 

Max.

Daily 

Max.

Instant 

Max.

Monthly 

Avg.

Daily 

Max.

SD001 NLR NLR 0.001 0.05 0.04 0.2 NLR NLR

SD002 30 100 NLR NLR NLR NLR NLR NLR

SD003 30 100 NLR NLR NLR NLR NLR NLR

SD004 NLR NLR NLR NLR NLR NLR NLR NLR

SD005 30 100 NLR NLR NLR NLR 10 15

SD006 30 100 NLR NLR NLR NLR 10 15

SD010 30 100 NLR NLR NLR NLR 10 15

SD012 NLR NLR NLR NLR NLR NLR NLR NLR

Source: MPCA 2006

NLR = No Longer Regulated

The permit outlines the effluent limitations and monitoring requirements of eight different 

discharge outfalls. In addition to the effluent limitations shown in Table 2-6, the permit 

describes the minimum number of sampling events that are required for each outfall, 

where necessary. Flow monitoring requirements (based on the time of year) are 

outlined for certain outfalls, as well as required pH monitoring, with the pH levels 

expected to be between 6.0 and 9.0 year-round. The permit also stipulates there will be 

no discharge of oil or other substances that result in a visible film, as well as no 

discharge of floating solids or visible foam.

The outfall effluent limitations in Table 2-7 were calculated based on the maximum 

discharge flow rates from Table 2-6. Outfall SD 001 is the circulating water system 

discharge canal, which discharges wastewater directly to the Mississippi River. A 

portion of the water from this canal is rerouted to the intake screenhouse during the 

winter months to help prevent ice build-up there. All of the following surface discharges 

(SD) are monitored outfalls; however, they are all discharged to the Mississippi via SD 

001, the circulating water system discharge canal. Steam generator blowdown is 

discharged via SD 002. Radwaste treatment system effluent is discharged via SD 003. 

The reverse osmosis system effluent is discharged via SD 004. SD 005 and SD 006 

discharge wastewater from the Unit 1 and Unit 2 turbine building sumps, which are 

comprised of noncontact cooling water, condensate traps and drains, roof and floor 

drains, Unit 1 and Unit 2 condensate blowdown and the heating system blowdown. SD 

010 discharges wastewater from miscellaneous floor drains. The Unit 1 and Unit 2 

cooling water systems are the plant’s two internal waste streams (WSs), WS 001 and 

WS 002. These waste streams contain bromine and chlorine residuals and are also 

discharged to the river via SD 001. 
Affected Environment

2-22

The only surface discharge aside from SD 001 that discharges directly to the Mississippi 

is 

SD 012. SD 012 discharges the plant intake screen backwash as well as the fish return 

system of any impinged fish, aquatic organisms, or debris directly to the river. 

Table 2-7. Surface Discharge (SD) and Internal Waste Stream (WS) 

Discharges from PINGP 1 and 2 (in millions of gallons per day [mgd])

Outfall

Maximum 

Flow

Average 

Flow 

No. (mgd) (mgd)

SD 001 864.0 503.0

SD 002 0.576 0.012

SD 003 0.230 0.002

SD 004 0.244 0.051

SD 005 0.360 0.030

SD 006 0.360 0.030

SD 010 0.015 0.001

SD 012 3.200 2.000

WS 001& 

WS 002 69.00 25.00

Source: MPCA 2006

Cooling water discharge is restricted at certain times of the year. From April 15 to April 

30 discharge is restricted to 194 mgd (7.34 x 105 m3

/day) if the flow of the Mississippi 

River is at or above 15,000 cfs (424.8 m3

/s). If the river flow is below this level, 

discharge is limited to 97 mgd (3.67 x 105 m3

/day). From May 1 to May 31 discharge is 

restricted to 194 mgd (7.34 x 105 m3

/day), from June 1 to June 15 the discharge rate 

may increase to 259 mgd (9.80 x 105 m3

/day), and from June 16 to 30 it may increase to 

517.5 mgd (1.96 x 106 m3

/day). Outfall SD 001 is permitted to exceed these discharge 

limitations only in the event that it is necessary in order to prevent condenser inlet 

temperatures from exceeding 85 °F (29 °C). 

Thermal limitations require temperature monitoring at five different locations: the 

discharge canal outfall (SW 001), the plant intake (SW 002), a specified point in the main 

river channel (SW 003), a specified point in Sturgeon Lake (SW 004), and a point 

downstream of Lock and Dam No. 3 (SW 001) which is to be monitored using three 

different temperature probes. The permit states that the daily average temperature 

should under no circumstances exceed 86 °F (30 °C) and that the temperature of the 

receiving water should not be raised over 5 °F (-15 °C) above the ambient water 

temperature. The permit specifies that if the ambient water temperature reaches 78 °F 

(26 °C) for two consecutive days all cooling towers should be operated to their maximum 

extent.
Affected Environment

2-23

2.1.7 Facility Water Use and Quality

The PINGP 1 and 2 circulating water system and the cooling water system both draw 

water from, and discharge to, the Mississippi River. Onsite ground water wells also 

supply water for cooling water makeup, domestic water consumption, and other 

industrial uses. The following sections detail water use at PINGP 1 and 2.

2.1.7.1 Ground Water Use 

A portion of the water utilized by PINGP 1 and 2 for its supplemental operations is 

ground water. Specifically, PINGP 1 and 2 uses ground water to supplement primary 

and secondary makeup cooling water, plant sanitary facilities, pump bearing lubrication, 

pump motor cooling, pump seal lubrication, domestic uses, and lawn watering 

(Minnesota Department of Natural Resources [MNDNR] Permit 865114). The plant 

draws onsite ground water from six wells screened in the surficial aquifer. The MNDNR

permits five of these wells for ground water withdrawal, while the sixth remains 

unpermitted because it draws less than 10,000 gallons per day (37.9 m3

/day) and 

therefore does not require a permit (MNDNR Permit 865114).

Sanitary wastewater is treated either with the site’s septic system or is transported to the 

Red Wing Wastewater Treatment Plant or the Prairie Island Community Water 

Treatment Plant because there is no onsite sanitary wastewater treatment facility (MPCA 

2006).

2.1.7.2 Surface Water Use

PINGP 1 and 2’s treatment and disposal systems include a chemical treatment system 

(in which water is treated with bromine and/or chlorine to control biofouling organisms), a 

reverse osmosis system, a radioactive waste treatment system, an intake screening 

system, and mechanical draft cooling towers (MPCA 2006). The surface water used in 

the plant’s circulating water system and the cooling water system is withdrawn from the 

Mississippi River through the plant’s intake structure and is eventually discharged back 

to the river via the discharge canal (MPCA 2006). 

PINGP 1 and 2 withdraw approximately 2.0 x 1011 gallons per year (848 cfs; 24 m3

/s) 

from the river annually under these conditions, with a highest recorded annual 

withdrawal of 2.08 x 1011 gallons (882 cfs; 25 m3

/s) in 2005 (TtNUS 2006). The intake 

structure is designed to pump river water into the system during both normal conditions 

and major flood levels. PINGP 1 and 2 have no formal protocol to accommodate 

extremely low river conditions because the upstream Lock and Dam 3 controls the river 

elevation at the site. However, the plant does have an emergency plan in the event of 

the loss of Lock and Dam 3.

Cooling tower blowdown discharge averages 1.9 x 1011 gallons per year (810 cfs; 23 

m3

/s), with a highest recorded average of 2.0 x 1011 gallons per year (851 cfs; 24 m3/s) in 

2000 (TtNUS 2006). Blowdown discharges back to the Mississippi via the plant’s 

discharge canal in a manner complying with the plant’s NPDES Individual Wastewater 

Discharge Permit No. MN 0004006 issued by MNDNR in 2006 (MPCA 2006). The 

primary sources of river water consumption and evaporation are drift losses and PINGP 

1 and 2 averages 9.2 x 109 gallons per year (39 cfs; 1.1 m3

/s). The plant’s consumptive 

river water use constitutes 4.6 percent of the Mississippi River flow at the site, which 

averages 18,380 cfs (520 m3

/s) annually (TtNUS 2006).
Affected Environment

2-24

2.1.7.3 Surface Water Quality

While no water quality studies have been conducted by PINGP 1 and 2 in recent years, 

the MPCA monitors water quality at Lock and Dam 3.

PINGP 1 and 2 are located in the Upper Mississippi Sub-basin, an area of the 

Mississippi River that has a number of water quality issues. Hypoxia, a zone of 

decreased dissolved oxygen, has become a serious problem in the Gulf of Mexico as a

result of nutrient enrichment, particularly nitrogen enrichment (EPA 2006). The 

Mississippi River is one of the two main nutrient contributors to the Gulf of Mexico and 

Minnesota in particular contributes an estimated five to six percent of this nitrogen flux to 

the Gulf of Mexico (EPA 2006). Management practices in the Upper Sub-basin are 

implemented to reduce nitrogen and phosphorus discharges into the river system 

(MPCA 2000).

Wastewater discharges from the PINGP 1 and 2 facility to the Mississippi River are 

regulated by the MPCA issued NPDES permit. In terms of surface water quality issues, 

the facility’s NPDES permit regulates effluent limitations, thermal limitations, and water 

intake restrictions. For a more detailed description of the NPDES permit, refer to Section 

2.1.6.3.

PINGP 1 and 2 implements a Storm Water Pollution Prevention Plan onsite to reduce 

the amount of pollution discharged through storm water runoff. The purpose of this plan 

is to eliminate any contact that discharged storm water may have with possibly 

contaminated materials.

2.1.7.4 Dredging

Since the original construction of the discharge canal, PINGP 1 and 2 have not

conducted any dredging aside from routine maintenance. In April 2010, PINGP 1 and 2 

performed several larger-scale maintenance dredging projects after receiving the 

appropriate permits (listed in Table 1-1) from the U.S. Army Corps of Engineers 

(USACE) and MNDNR (Xcel Energy 2010). The dredging activities included work on the 

main discharge canal and the intake channel (Xcel 2010). NSP has stated that it

implements and will continue to implement best management practices to reduce 

pollution risks during any dredging activities at PINGP 1 and 2.

2.2 Affected Environment

This section provides general descriptions of the environment near PINGP 1 and 2 as 

background information. This section also provides detailed descriptions where needed 

to support the analysis of potential environmental impacts of refurbishment and 

operation during the renewal term, as discussed in Chapters 3 and 4. Section 2.2.9 

describes historic and archaeological resources in the PINGP 1 and 2 area, and Section 

2.3 describes the possible impacts associated with other Federal project activities.

2.2.1 Land Use

PINGP 1 and 2 are located on approximately 578 ac (234 ha) of land, owned by NSP.

Prior to construction of PINGP 1 and 2, the site was used for agriculture. Approximately 

240 ac (97 ha) were disturbed and modified by plant construction activities in the early 

1970s. The developed portion of the PINGP 1 and 2 site, which occupies approximately 

60 ac (24 ha), consists of the power plant structure and associated buildings, 

PINGP 1 and 2
Affected Environment

2-25

maintenance facilities, parking lots (AEC 1973). The remaining 180 ac (73 ha) of 

disturbed land were landscaped after construction was completed and most of this land 

is grassland (AEC 1973). The remainder of the site (about 338 ac [137 ha]) is primarily 

wooded. Figure 2.2 depicts the general site layout and exclusion zone boundary. The 

exclusion zone boundary extends east of the plant to the main channel of the Mississippi 

River. Islands within this boundary, as well as a small strip of land northeast of the plant, 

are owned by the U.S. Army Corps of Engineers (USACE) (NMC 2008).

The Prairie Island Indian Community (PIIC) is a Federally-recognized Indian Tribe 

organized under the Indian Reorganization Act (25 USC 476). PINGP 1 and 2 are 

located immediately south, south-east of the Prairie Island Indian Community. It is 

because of the PINGP 1 and 2’s location relative to the PIIC that the Tribal Council 

asked to be a Cooperating Agency for purposes of developing sections of the 

supplemental Environmental Impact Statement (SEIS) for the PINGP 1 and 2 license 

renewal environmental review.

PIIC

The PIIC has gained land through several Federal reorganization acts and direct 

purchases by the Tribal Council. The PIIC’s land holdings now total over 3000 ac (1200 

ha) (both land and water). The PIIC has grown substantially since PINGP 1 and 2 first 

went on-line in 1973. Currently, the PIIC consists of 801 enrolled band members, of 

whom approximately 250 members reside within 2 mi (3.2 km) of PINGP 1 and 2 on 

tribal lands. PIIC’s reservation contains 60 housing units on the reservation, new Trust 

lands (i.e., the Upper Island) hold 29 housing units, and 47 additional units are proposed 

for 2009. (See Chapter 4, Figure 4-1) (PIIC 2009) 

The PIIC owns and operates the Treasure Island Resort and Casino, which is on 

reservation land and located within 1 mi (1.6 km) of PINGP 1 and 2. Treasure Island 

also includes a 24-lane bowling center, a multi-use event center, an RV park, a marina, 

and a sightseeing and dinner cruise boat. (PIIC 2009)

Because of its unique legal and political status as a Federally-recognized Indian Tribe, 

the Prairie Island Indian Community is not subject to State or local land use jurisdiction. 

The Tribe is free to develop its own land-use policies and management plans for its 

Trust lands. (PIIC 2009)

2.2.2 Air and Meteorology

2.2.2.1 Climate and Meteorology

Minnesota’s climate is characterized by the Koppen Climate Classification System as 

humid continental, or Dfa, in which precipitation is low, but adequate, and seasonal 

temperatures vary greatly (Strahler 1984). The region is subject to temperature extremes 

in winter from continental polar and/or Arctic air masses, and in summer from tropical air 

masses moving in from the Gulf of Mexico, which can cause occasional extended 

periods of heat (NCDC 2006). Common storm systems include Alberta Clippers, fast 

moving air masses with low pressure that develop in the north in winter months and 

move southward, and Panhandle Hooks, low pressure air masses that form in the 

southwest and move northeast and often carry significant moisture (NWS 2008a; NWS 

2008b). Statewide mean monthly temperatures range from 4 °F (-15 °C) in January to 70 

°F (20 °C) in July (NCDC 2006). Data collected from 1949 to 2001 at the Red Wing Dam 

3 weather station indicate that the mean monthly temperatures in the vicinity of PINGP 1 

and 2 range from 12.0 °F (-11 °C) in January to 72.1 °F (22.2 °C) in July (MRCC 2001). 
Affected Environment

2-26

Statewide 1-day temperature extremes range from -60 °F (-51 °C) to 114 °F (45.6 °C) 

(NCDC 2006).

Mean annual precipitation ranges from 35 in. (89 cm) in the southeastern portion of the 

state to 19 in. (48 cm) in the northwest portion of the state (NCDC 2006). Data collected 

from 1971 to 2000 at the Red Wing Dam 3 weather station indicate that the mean annual 

precipitation in the vicinity of PINGP 1 and 2 is 29.95 in. (76.07 cm); the period June 

through August receives the highest mean precipitation (NCDC 2000). Approximately 

two-thirds of annual precipitation occurs between May and September, which coincides 

with the April-to-October native growing season and May-to-September row crops 

growing season (NCDC 2006). Thunderstorms are most common during months of 

heavier rainfall. Southern Minnesota averages 45 thunderstorm days annually (NCDC 

2006).

Statewide annual snowfall varies greatly and averages from 40 in. (102 cm) in the 

southern portion of the state to 70 in. (180 cm) in the northeastern portion of the state 

(NCDC 2000). In the vicinity of the PINGP 1 and 2 site, annual snowfall averages about 

44 in. (112 cm) per year (NMC 2008). Snowfalls of 4 in. (10 cm) or greater are common 

from mid-November to mid-April and snowfall with blizzard conditions occur about two 

times per year (NCDC 2006).

Average annual wind speed documented over a 30-year period is 10.6 mph (17.1 kph) 

for Minneapolis, 39 mi (63 km) northwest of PINGP 1 and 2 (NCDC 2005). Prevailing 

wind directions for the site region are northwest in the winter months, east-southeast in 

the early summer, and south in the late summer months (NCDC 1998). In the vicinity of 

the PINGP 1 and 2 site, wind direction is primarily influenced by the Mississippi River 

Valley.

Tornadoes have been documented in Minnesota from March through November and 

occur most frequently in May, June, and July (MCWG 2008). These months account for 

over 75 percent of observed tornadoes, of which June accounts for 33 percent of these 

(NCDC 2006). Goodhue County has 18 recorded tornadoes between the period of 1950 

to 2005 (NWS 2005). Of these, all occurred between May and August; twelve were F0, 

four were F1, and one was an F3 on the Fujita Tornado Damage Scale (NWS 2005).

The PINGP 1 and 2 Meteorological Monitoring Program, which is part of the PINGP 1 

and 2 Environmental Monitoring Program, includes operation of weather instruments 

mounted on a primary 140-ft (42.6-m)-high tower, which is located approximately 1800 ft 

(549 m) northwest of the reactor building. Wind speed, direction and temperature 

variance are measured at 33 ft 

(10 m) and 197 ft (60 m). Precipitation is measured at ground level. This meteorological 

data is gathered once per hour and stored in a database, which is reviewed daily. 

Quality controlled meteorological data is then compiled into monthly, quarterly and 

annual reports.

2.2.2.2 Air Quality

Under the Clean Air Act (CAA), the EPA has established National Ambient Air Quality 

Standards (NAAQS) six criteria pollutants: nitrogen dioxide, sulfur dioxide, carbon 

monoxide, lead, ozone, and particulate matter (PM10 and PM2.5). Under the NAAQS, 

areas are designated as being in “attainment” or “non-attainment” for the standards 

established for each criteria pollutant. Areas that are re-designated attainment after 

being designated non-attainment are considered “maintenance areas.” In addition to 
Affected Environment

2-27

meeting the air quality standards, maintenance areas must create a plan describing how 

the area will continue to meet the air quality standards over a 10-year period.

Goodhue County, in which PINGP 1 and 2 are located, is part of the Southeast 

Minnesota-LaCross (Wisconsin) Interstate Air Quality Control Region (40 CFR 81.66). 

All of these counties, with the exception of Olmsted County, are in attainment (NMC 

2008). Olmsted County, which is approximately 65 mi (105 km) from the PINGP 1 and 2 

site, is a maintenance area for sulfur dioxide and PM10 (40 CFR 81.324).

PINGP 1 and 2 have a number of stationary emission sources, which include eight

standby emergency power supply diesel engines, two PINGP 1 and 2 generators are 

tested periodically to ensure their continued performance capability, and NSP has 

procedures in place to ensure continuous monitoring, sampling, and filtering of the oil. 

Used oil is collected for offsite disposal; waste management is discussed in Section 

2.1.3.

2.2.3 Ground Water Resources

Prairie Island is an island terrace within a three mile wide valley of the Mississippi River 

floodplain. Six ground water wells utilize the surficial aquifer directly beneath the site. 

The deepest of these wells extends to 165 ft (50.3 m) (NMC 2008). This alluvial aquifer 

(or, water table) is 130 to 200 ft (39.6 to 60.9 m) thick and is composed of sands, 

gravels, and other finer-grained lake sediments resulting from glacial outwash (Cowdery 

1999). The water table is found 5 to 20 ft (1.5 to 6.1 m) underneath the PINGP 1 and 2

site. The ground water flow in the surficial aquifer is influenced directly by its hydraulic 

surface water boundaries: the Mississippi River to the northeast and the Vermillion River 

to the southwest. Typically, the ground water flows southwest from the Mississippi to the 

Vermillion (Winterstein 2001). However, in the spring if there are conditions of snowmelt 

or heavy rain, a ground water mound can form, resulting in radial flow (Cowdery 1999). 

Recharge to the aquifer comes from interaction with these surface water systems as well 

as from rain, snowmelt and floodwater. A sediment barrier limits the recharge and 

discharge flow interaction between the surficial aquifer and the surface waters (Ruhl 

2002). 

The area’s primary aquifers are found in bedrock composed of layers of limestone and 

sandstone. The Prairie du Chien Group and Jordan Sandstone are the uppermost of 

these aquifers (See Figure 2-1). The Jordan Sandstone is a confined aquifer and the St. 

Lawrence Formation separates it from the underlying Franconia Formation. Because the 

Mississippi River Valley cuts through these formations, forming the bluffs on either side 

of the valley, the Franconia Formation is the aquifer found directly beneath the shallow 

alluvial aquifer at the PINGP 1 and 2 site and is less thick at this point than its total 

measured thickness of 180 feet (24.4 m).
Affected Environment

2-28

The upper three strata discharge from the bluffs as springs, while the deeper Franconia 

Formation discharges to the sediments that partially fill the Mississippi Valley. Beneath 

the Franconia Formation is the Dresbach formation, which consists of sandstone, 

siltstone and shale and measures over 100 ft (30.5 m) in thickness. The Dresbach 

formation includes the Mount Simon formation, which is the primary water producing 

aquifer for the nearby community of Red Wing and the PIIC. The wells at the PINGP 1 

and 2 site, however, draw water from the shallow alluvial aquifer. The Cowdery study 

notes that despite a high hydraulic head gradient between aquifers, the exchange of 

water between the alluvial aquifer and the bedrock aquifer below is small because of a 

boundary of clay-rich materials between the two strata. (Cowdery 1999)

2.2.3.1 PINGP 1 and 2 Water Supply Wells

PINGP 1 and 2 have six onsite wells screened in the surficial aquifer (NMC 2001q). Five 

of these wells are permitted for ground water withdrawal by MNDNR, while the sixth 

remains unpermitted because it draws less than 10,000 gpd (37.9 m3

/day) and therefore 

does not require a permit (NMC 2006a). The two largest of these wells are 165 ft (50.3 

m) in depth and 10 inches (25.4 cm) in diameter and yield up to 116,000 ft3

/day (3,285 

m3

/day) of ground water.

The average total yield of the five permitted wells is 91 gpm (5.7 x 10-3 m3

/s), with the 

unpermitted well averaging 1 gpm (6.3 x 10-5 m3

/s), resulting in a total annual average 

yield of 92 gpm (5.8 x 10-3 m3

/s) from 2000 to 2005 (See Table 2-8). The highest 

recorded annual average yield occurred in 2005 at 118 gpm (7.4 x 10-3 m3

/day) and the 

lowest was recorded in both 2000 and 2002 at 77 gpm (4.9 x 10-3 m3

/day).

Figure 2-5. Lithology and Generalized Geologic Section for the 

Prairie Island Low Island Terrace (Source: Cowdery 1999)
Affected Environment

2-29

Table 2-8. Total Annual Ground Water Withdrawal (Gallons) for PINGP 1 

and 2.

Year

Well Well Well Well Well Well Total Annual

(Nonpermitted)256120 256121 611076 402599 [BLANK] gal gpm

2000 - 13,676,800 12,812,800 3,745,780 7,474,900 2,242,900 39,953,180 76

2001 - 16,974,300 16,372,060 3,663,190 7,267,700 2,971,700 47,248,950 90

2002 - 18,958,300 11,609,300 3,550,800 4,280,700 1,674,100 40,073,200 76

2003 - 10,648,800 14,248,900 4,163,190 10,969,500 1,884,000 41,914,390 80

2004 563,100 18,576,900 13,336,200 5,280,430 15,517,800 1,824,900 54,536,230 104

2005 563,100 20,833,300 19,933,600 6,830,210 12,055,695 1,946,200 61,599,005 117

Total Withdrawal 99,668,400 88,312,860 27,233,600 57,566,295 12,543,850 285,324,955 -

Avg. Annual Withdrawal 16,611,400 14,718,810 4,538,933 9,594,383 2,090,633 47,554,159 -

Avg. gpm 1.07 32.00 28.00 9.00 18.00 4.00 - 91

Source: [NMC 2008]

2.2.3.2 PINGP 1 and 2 Ground Water Monitoring

Ground water monitoring at PINGP 1 and 2 is primarily targeted at the ground water

infiltration of radionuclides such as tritium. Tritium is a product of manmade sources, as 

well as natural processes. Ground water sampling first revealed detectable levels of 

tritium in a nearby residence well in 1989, which led to the first establishment of a tritium 

sampling program at PINGP 1 and 2. In 1991, the plant modified the discharge canal by 

lengthening the submerged liquid radioactive waste discharge pipe. This pipe ensured 

that all liquid radioactive waste discharges from the plant were monitored and released 

towards the end of the canal, preventing any radioactive water from remaining in the 

discharge canal long enough to allow tritium to leach into the ground water supply. In 

response to an unusually high tritium sample (1360 picocuries per liter [pCi/L]) in one of 

the onsite wells, the plant replaced an aging pipe system in 1992. (NMC 2006s)

Conclusions drawn from the 2006 Radiological Environmental Monitoring Program 

Annual Report indicate that, while tritium levels detected in that same onsite well 

fluctuate from year to year, high tritium levels have not been detected since the plant 

took steps towards the prevention of tritium leaching. All ground water sampling, both 

onsite and offsite, has yielded results well below the EPA’s tritium drinking water 

standard of 20,000 pCi/L. (NMC 2006s)

NSP has implemented a ground water monitoring program that follows the guidelines of 

the Nuclear Energy Institute’s Ground Water Protection Initative. Results from the 

ground water monitoring are documented in a Radiological Environmental Monitoring 

Program Report which is submitted annually to the NRC.

2.2.4 Surface Water Resources

PINGP 1 and 2 are located on Prairie Island, which is on the Mississippi River. The 

Mississippi is the longest river in North America and spans 2302 mi (3705 km) from its 

source at Lake Itasca in Minnesota to where it empties into the Gulf of Mexico. The river 
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2-30

drains approximately 189,000 square miles and 31 different states. The Mississippi can 

be divided into six sub-basins: the Upper Mississippi River, Lower Mississippi River, 

Arkansas Red-White River, Ohio River, Missouri River, and Tennessee River Subbasins. The PINGP 1 and 2 facility is located in the Upper Mississippi sub-basin. (EPA 

2006)

The Upper Mississippi Sub-basin covers 20,100 square miles and has 12 major 

tributaries, the most notable being the Missouri River, the Illinois River, the Wisconsin 

River, and the Iowa River (MPCA 2008). Annual average discharge of this portion of the 

river ranges from 9,180 cfs to 204,800 cfs (259.9 to 5799.2 m3

/s). (USGS 2006)

Prairie Island itself is a low-lying island located in a one to three mile-wide (1,609 to 

4,828 m) section of the Mississippi River Valley, with the majority of the island being less 

than 25 feet 

(7.6 m) above the river. On either side of the valley are 360 foot high (110 m) bluffs 

composed of Paleozoic limestones and sandstones (Cowdery 1999). Prairie Island is 

located between the Mississippi River and the Vermillion River, with the confluence of 

the two rivers at the downstream end of the island (EPA 2006). About 1.5 miles (7920 ft) 

downstream from the island is Lock and Dam Number 3, which controls the water level 

and flow of this stretch of the Mississippi (USGS 2006). Typically, the Mississippi is kept 

at a water level higher than that of the Vermillion River and discharge from Lock and 

Dam Number 3 tends to be at its peak in the spring and summer. (Cowdery 1999) 

PINGP 1 and 2 are located on Sturgeon Lake, an area of the Mississippi created by the 

rise in water elevation by Lock and Dam Number 3 and the subsequent flooding of 

sections of the floodplain. The nearest upstream flow monitoring station to PINGP 1 and 

2 is the Prescott U.S. Geological Survey (USGS) monitoring station, located at river mile 

811.4. The nearest downstream flow monitoring station is the Winona USGS monitoring 

station, located at river mile 725.7. At the Prescott station the annual recorded mean 

flow from 1928 to 2005 is 18,380 cfs (520.5 m3

/s), with the highest annual mean flow 

being 38,540 cfs (1,091 m3

/s) and the lowest 4,367 cfs (123.7 m3/s). At the downstream 

Winona station the annual recorded mean flow from 1928 to 2005 is 29,590 cfs (837.9 

m3

/s), with the highest annual mean flow being 56,850 cfs (1,610 m3/s) and the lowest 

9,742 cfs (276 m3

/s). Table 2-9 and 2-10 show the monthly average and yearly total 

discharge flows at Lock and Dam 3 from 1999 to 2006 respectively. (USGS 2006)
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Table 2-9. Monthly Average Discharge Flow at Lock and Dam 3 from 1999 

to 2006

Month

Monthly Average

(cfs)

January 10,425

February 10,621

March 15,654

April 44,634

May 39,562

June 33,758

July 23,641

August 14,223

September 13,294

October 16,084

November 14,578

December 11,455

Source: USGS 2006

Table 2-10. Total Yearly Discharge Flow at Lock and Dam 3 from 1999 to 

2006

Year

Total Discharge Flow 

(cfs)

1999 272,245

2000 168,796

2001 355,385

2002 280,864

2003 198,688

2004 221,612

2005 272,099

2006 213,727

Source: USGS 2006

2.2.5 Description of Aquatic Resources

PINGP 1 and 2 are located on the west bank of the Mississippi River, north of Red Wing, 

Minnesota. The cooling system withdraws from and discharges to the Mississippi, 13 

river miles (21 river kilometers) below the confluence of the St. Croix River and 4 river 

miles north of where the Vermillion River joins the Mississippi (AEC 1973). The 
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Mississippi is dammed for navigation about 1.0 mi (1.6 km) downstream from the facility 

by Lock and Dam 3. The area of the river adjacent to PINGP 1 and 2 is known as Pool 3, 

and is bounded by Lock and Dam 3 (downstream) and Lock and Dam 2 (upstream), 

which lie about 18 river miles (29 river kilometers) apart (NMC 2008). Immediately north 

and east of the plant is Sturgeon Lake, a side slough or impoundment that would be 

considered a marsh if it were not associated with the main stem of the river (AEC 1973). 

The Vermillion River borders the southwest of the site. The power transmission system 

includes five in-scope lines, which cross a variety of water bodies, as discussed in 

Section 2.1.5.

Because the river is always changing, the exact length of the Mississippi River varies. 

According to USGS, the river flows about 2300 mi (3700 km), from Lake Itasca in 

Minnesota to the Gulf of Mexico (NPS 2008a). The Mississippi River Basin, which drains 

41 percent of the continental United States, a total area between 1.2 and 1.8 million mi2

(3.1 and 4.7 million km2

), and includes all or portions of 31 states and 2 Canadian 

provinces, is divided into six subbasins: Upper Mississippi River, Lower Mississippi 

River, Arkansas Red-White River, Ohio River, Missouri River, and Tennessee River 

(NPS 2008a).

Mississippi River and River Basins

The Upper Mississippi River, flowing about 1300 mi (2100 km) from the head waters in 

Lake Itasca to the confluence of the Ohio River, was dammed to provide 9-ft (2.7-m) 

deep channels for navigation, and is not used for flood control (UMRBA undated; 

USACE 2004). As described above, PINGP 1 and 2 are located on the Minnesota shore 

of Pool 3, the area of the Mississippi River created by Lock and Dams 2 and 3. The 

normal level of Pool 3, 674.5 ft (205.6 m) above mean sea level, is controlled by Lock 

and Dam 3, located a little over a mile downstream from the facility (NMC 2008).

Phytoplankton and zooplankton were monitored in preoperational studies, but have not 

been studied since (NMC 2008; AEC 1973). Monitoring showed high phytoplankton 

densities in the vicinity of the plant. Dominant species indicated eutrophic conditions, 

and pollution-tolerant species were common. Zooplankton was primarily rotifers, 

crustaceans, and protozoa. Phytoplankton and zooplankton communities may have 

changed in the decades since these studies were performed.

Due to barge navigation, much of the river bottom at the time of preoperational 

monitoring was scoured so that only the sand and clay substrate remained, and very 

little benthic fauna. The areas that were not so disturbed by shipping were dominated by 

midge fly larvae and oligochaetes, as well as tubificid worms, groups generally tolerant 

of severe pollution and environmental disturbance. Pollution-tolerant macroinvertebrates, 

such as caddisflies and mayflies, had begun to establish themselves just above Lock 

and Dam 3, downstream of the discharged waste and runoff from the urban areas, 

Minneapolis and St. Paul, Minnesota. The FES for PINGP 1 and 2 reported only a few 

small clam beds in the area, without giving more details on the species present, and 

indicated that areas monitored upstream on the Mississippi River and on the St. Croix 

revealed a higher diversity of species, which generally increased as water quality 

increased. (AEC 1973)

In 2000 and 2001, MN DNR conducted a survey of mussels in the Mississippi National 

River and Recreation Area Corridor for the National Park Service (Kelner and Davis 

2002). The southern-most reach of study sites was Upper Pool 3, defined from Lock and 

Dam 2 to approximately 9 river miles (14 km) upstream of PINGP 1 and 2. Among the 

areas studied, Upper Pool 3 was the most species-rich area of the survey, and second in 
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2-33

overall mussel abundance – Upper Pool 2 had the highest abundance. The 2,486 

mussels collected covered 23 species; the top three species were O. relexa (47.2 

percent), A. plicata (25.0 percent), and F. flava (10.1 percent). A high number of empty 

shells were collected, indicating that the historic number of species was at least 37 

species. The survey also found that 2.6 percent of native mussels in Upper Pool 3 were 

infested by zebra mussels (Dreissena polymorpha), the highest level of infestation in the 

study.

In 1988, the non-native zebra mussel made its first appearance in the United States, in 

Lake St. Clair near Detroit, Michigan. By 1990, the invasive bivalve had colonized in all 

the Great Lakes, and by 1992, established populations in many major rivers, including 

the Mississippi (Benson 2008). In the Upper Mississippi River System, adults or veligers 

(free-swimming larvae) have been identified as far upriver as Lock and Dam 1 (River 

Mile [RM] 848) (rkm 1365) by St. Paul, Minnesota and as far downriver as Lock and 

Dam 24, at Hannibal, Missouri (Tucker et al. 1993; MNDNR 2008i). Annual surveys of 

zebra mussel population densities conducted in the lower St. Croix River from 2005 

through 2007 showed a dramatic increase in the relative abundance of zebra mussels at 

Prescott, located at the confluence of the Mississippi River and St. Croix River (RM 815, 

rkm 1312), about 11 mi (18 km) upriver from PINGP 1 and 2 (RM 797, rkm 1283). The 

density of zebra mussels increased over the three-year study from 72/m2 (86/yd2

) to 

574/m2 (686/yd2

). Four miles upriver of Prescott on the St. Croix River at St. Croix Bluffs, 

the density of zebra mussels increased exponentially during this same period from 89/m2

(106/yd2

) to 12,288/m2 (14,696/yd2) (NPS 2008b).

Zebra mussels are filter feeders and are one of the only freshwater mollusks capable of 

firmly attaching themselves to solid objects, using adhesive structures called byssal 

threads (WDNR 2004). They are often found in large numbers attached to various 

underwater objects, including boat hulls, pilings, pipes, rocks, other larger bivalves, and 

each other (USGS 2008). Females can produce up to one million eggs annually 

(MNDNR 2008i), and the fertilized eggs develop into larvae, or veligers. The veligers 

swim in the water column for one to five weeks and then begin to sink. The veligers then 

attach to a solid surface where they metamorphose to adult shape, grow, and eventually 

reproduce, often reaching reproductive maturity in the first year (WDNR 2004). Zebra 

mussels can live from three to nine years (USGS 2008).

At high densities zebra mussels can cause severe biofouling of water intake structures 

and irrigation systems and can cause severe ecological problems. Zebra mussels will 

frequently colonize the intake pipes of public water supply plants and the cooling water 

intake structures at power plants, and may reduce by two-thirds the diameter of the 

intake pipes, thereby constricting cooling water flow. In a USACE study, zebra mussels 

colonized upon native mussels at an average infestation rate of 5 to 58 zebra mussels 

per native mussel (NPS 2008b). At higher colonization densities zebra mussels can 

smother native mussels. Their filter feeding can effectively deplete the water column of 

suspended planktonic organisms used for food by other aquatic organisms, including 

fish and native mussels (WDNR 2004). Even though waterfowl and fish such as the 

common carp feed on zebra mussels (WDNR 2004; Tucker et al. 1996), once the zebra 

mussels have become established in a waterway, there is very little that can be done to 

control their numbers (WDNR 2004).

Preoperational monitoring (1969-1971) indicated that the composition of the fish 

population varied between the lower end of Pool 3 and upstream portion of Pool 4 

(downstream of Lock and Dam 3), due to the difference in flow. Slow currents above the 

dam yielded a relatively stable, lake-like habitat, while downstream of Lock and Dam 3 
Affected Environment

2-34

exhibited a fast-water, riverine habitat. Rough (non-game) fish, such as common carp 

(Cyprinus carpio), and redhorse (Moxostoma spp.) made up about 66 percent of the 

species in Pool 3 and 87 percent of the species in Sturgeon Lake, with game species, 

including black crappie (Pomoxis nigromaculatus), white crappie (P. annularis), and 

white bass (Morone americana), making up the remaining species. Pool 4 had a much 

higher proportion of game fish, including walleye (Stizostedion vitreum) and sauger (S. 

canadense), and was considered a major spawning and rearing area for game fish, 

compared to Pool 3. (AEC 1973)

Sections 316 (a) and 316(b) of the Clean Water Act (CWA) requires that the location, 

design, construction, and capacity of the cooling water intake structures reflect the best 

technology available (BTA) in order to minimizing adverse environmental impacts, 

specifically impingement and entrainment, to protect fish, shellfish, and other forms of 

aquatic life (33 USC 1326). Phase II of Section 316(b)’s implementing regulations 

applies to large existing electric generating plants, such as PINGP 1 and 2, that 

withdraw more than 50 million gallons of water per day (gpd; 6.7 million cubic feet per 

day [cfd]). The EPA implemented Phase II on July 9, 2004 (69 FR 41575). The new 

Phase II performance standards were designed to significantly reduce impingement 

mortality due to water withdrawals associated with cooling water intake structures used 

for power production and were to be implemented through the National Pollution 

Discharge Elimination System (NPDES) permitting process. The rule would require 

licensees to demonstrate compliance with Phase II performance standards upon 

renewal of their NPDES permit. To attain a renewed NPDES permit, licensees may have 

been required to alter their intake structure, redesign the cooling system, modify station 

operation, or take other mitigative measures to comply with the Phase II regulations.

However, EPA suspended the Phase II rule on July 9, 2007 (72 FR 37107) in response 

to the Second Circuit Court of Appeals decision in Riverkeeper, Inc. v. EPA, No. 04-

6692. As a result, the EPA directed NPDES permit writers for Phase II facilities to 

develop technology-based permit conditions on a case-by-case basis using all 

reasonably available and relevant data and Best Professional Judgment (BPJ) as to the 

BTA.

PINGP 1 and 2 conducted monitoring as a requirement of Sections 316(a) and 316(b) of 

the Clean Water Act. Gizzard shad (Dorosoma cepedianum), white bass, freshwater 

drum (Aplodinotus grunniens), and common carp made up over half the fish collected 

between 1973 and 1976 (NMC 2008). In later years (1988-2006), the relative abundance 

of eight species (carp, white bass, freshwater drum, sauger, black crappie, shorthead 

redhorse [Moxostoma macrolepidotum], walleye, and gizzard shad) ranged from 69 to 

89 percent of all fish caught each year (ESWQD 2005). The status of eight species 

(carp, white bass, freshwater drum, sauger, shorthead redhorse, walleye, gizzard shad, 

smallmouth bass [Micropterus dolomieui], and largemouth bass [Micropterus salmoides]) 

is discussed in each annual environmental monitoring report. Each of these eight 

species was considered “relatively stable” in the last available annual report (ESWQD 

2005).

The Minnesota Department of Health (MDH) has published fish consumption guidelines 

for the general public and for sensitive groups, defined as women who are or may 

become pregnant and children under the age of 15, due to the presence of mercury, 

PCBs, and perfluorooctanesulfonic acid (PFOS). For Pool 3, from Hastings Dam to Red 

Wing, MDH recommends no more than one meal per week of bluegill sunfish (Lepomis 

macrochirus), crappie, (Pomoxis spp.), flathead catfish (Pylodictis olivaris), freshwater 

drum, largemouth bass, northern pike (Esox lucius), sauger, smallmouth bass, walleye 
Affected Environment

2-35

for both the general public and sensitive groups. Additionally, for sensitive groups, 

flathead catfish larger than 20 in. should not be eaten more than once a month. MDH 

recommends both the general public and sensitive groups eat no more than one meal 

per month of buffalo fish (Ictiobus spp.), carp (Cyprinidae), channel catfish (Ictalurus 

punctatus), and white bass. (MDH 2008a; MDH 2008b)

2.2.6 Terrestrial Resources

The 578-ac (234-ha) PINGP 1 and 2 site is located on the west bank of the Mississippi 

River on a low island terrace of the Mississippi River floodplain. This region is 

characterized by prairie land, bluffs, and stream valleys that range from 500 to 600 ft 

(150 to 180 m) in depth (MNDNR 2006b). The PINGP 1 and 2 site is composed of flat to 

slightly rolling topography (NMC 2008). The Vermillion River lies to the west of Prairie 

Island, and the Mississippi River lies to the east.

Approximately 60 ac (24 ha) of the PINGP 1 and 2 site contain the generating facility, 

associated buildings, parking lots, and roads (NMC 2008). An additional 180 ac (73 ha) 

of previously disturbed land has been converted to maintained grassy areas or prairie 

grassland habitat (NMC 2008). The remaining 338 ac (137 ha) consist of wooded areas 

characteristic of eastern broadleaf forests (NMC 2008). Vegetation varies by type of 

habitat found on the PINGP 1 and 2 site, which includes floodplain, flat uplands, northfacing slopes, and south-facing slopes. White oak (Quercus alba), red oak (Q. rubra), 

black oak (Q. velutina), bitternut hickory (Juglans cinerea), and shagbark hickory (Carya 

ovata) comprise the dominant species in oak-hickory forests of eastern broadleaf habitat 

(USFS Undated). Additionally, the FES (AEC 1973) for PINGP 1 and 2 also noted the 

presence of silver maple (Acer saccharinum), cottonwood (Populus deltoids), and green 

ash (Fraxinus pennsylvanica) within floodplain areas; burr oak (Q. marcrocarpa), pin oak 

(Q. ellipsaidalis), and eastern red cedar (Juniperus virginiana) within flat uplands; sugar 

maple (A. saccarum), American basswood (Tilia americana), paper birch (Betula 

paprifera), ironwood (Carpinus caroliniana), and black walnut (Juglans nigra) on northfacing valley slopes; and trembling aspen (P. tremuloides) and bitternut hickory (Carya 

cordiformis) on south-facing slopes (AEC 1973; NMC 2008). Major shrub species that 

occur within a 10-mi (16-km) radius of PINGP 1 and 2 include bittersweet (Celastrus 

scandens), red-osier dogwood (Cornus stolonifera), river grape (Vitis riparia), red 

raspberry (Rubusindaeus spp.), Virginia creeper (Parthenocissus quinquefolia), and 

prickly ash (Xanthoxylum americanum) (AEC 1973).

The PINGP 1 and 2 site contains and is surrounded by freshwater emergent wetland 

and freshwater forested/shrub wetland habitat, as indicated by the U.S. Fish and Wildlife 

(FWS) National Wetlands Inventory database (FWS 2008c). Though these areas remain 

undisturbed, no wetlands on or near the PINGP 1 and 2 site have been officially 

delineated.

A variety of wildlife is found in the forested and grassland communities on and in the 

vicinity of the PINGP 1 and 2 site. The small fragmented forest tracts in the northern 

portion of the site provide habitat for small mammals such as raccoons (Procyon lotor), 

gray squirrels (Sciurus carolinensis), and fox squirrels (S. niger) as well as birds such as 

wood warblers, thrushes, woodpeckers, kinglets and hawks (NMC 2008). Larger spans 

of wooded areas found on the southern portion contain sloughs and lakes, which support 

salamanders, frogs, and other amphibians as well as birds, including numerous duck 

species and wading birds (AEC 1973; NMC 2008).
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The Mississippi River Valley is a major North American migratory flyway. Approximately 

40 percent of migratory birds and waterfowl in the U.S. use the flyway as their primary 

migration corridor (NPS 2006a). Migrating birds commonly observed on and in the 

vicinity of the PINGP site include herons, hawks, plovers, terns, flycatchers, nuthatches, 

wrens, thrushes, shrikes, warblers, and blackbirds (AEC 1973; NMC 2008). Additionally, 

the FES for PINGP 1 and 2 noted a number of bird species that have been recorded to 

nest within 10 mi (16 km) of the site, which included wading birds such as great blue 

herons (Ardea herodias) and green herons (Butorides virescens); raptors such as 

Cooper’s hawks (Accipiter cooperii), red-tailed hawks (Buteo jamaicensis), northern 

harriers (Circus cyaneus), great horned owls (Bubo virginianus), and barred owls (Strix 

varia); and songbirds such as black-capped chickadees (Poecile atricapillus), wrens, 

thrushes, cedar waxwings (Bombycilla cedrorum), belted kingfishers (Megaceryle 

alcyon), horned larks (Eremophila alpestris), and whip-poor-wills (Caprimulgus 

vociferous) (AEC 1973). More detailed listings of migratory bird species and nesting bird 

species recorded to be common to the PINGP 1 and 2 site can be found in Appendix A 

of the FES for PINGP 1 and 2 (AEC 1973).

Purple loosestrife (Lythrum salicaria), a perennial herb, one of two terrestrial invasive 

species that has been documented on the PINGP 1 and 2 site. The plant is native 

throughout Europe and Asia and was introduced to the U.S. in the 1800s (PCA 2006). 

Purple loosestrife can invade wetland areas and outcompete native grasses and sedges 

to form dense stands (PCA 2006). NSP does not manage purple loosestrife populations 

as the species has not been found to interfere with any intake structures or operation of 

the facility.

Common buckthorn (Rhamnus cathartica) has also been observed on the PINGP 1 and 

2 site and was also brought to the U.S. in the mid-1800s from Europe. The common 

buckthorn is considered one of the most invasive species in Minnesota. Buckthorn is a 

problem because it out-competes native plants for moisture, light and nutrients, lacks the 

natural controls of insects or disease to curb growth, and can aggressively invade 

wetlands. NSP does not use any method to control the growth of common buckthorn.

The Mississippi National River and Recreation Area corridor lies about 20 mi (32 km) 

northwest of the PINGP 1 and 2 site and spans 72 mi (116 km) of the Mississippi River 

from Hastings, Minnesota to

Ramsey, Minnesota (NMS 2008; NPS 2006b). The corridor encompasses part of the 

Mississippi flyway and provides habitat for more than 50 species of mammals, 270 

species of birds, 150 species of fish, and 25 species of mussels (NPS 2006a). More than 

a dozen pairs of bald eagles (Haliaeetus leucocephalus) nest within the corridor, and 

several heron, egret, and cormorant rookeries exist along the river as well (NPS 2006a). 

The corridor contains a variety of eastern deciduous forest and tall grass prairie 

communities, which include floodplain forest, upland prairie, maple-basswood forest, 

oak-savanna, dry oak forest, mesic oak forest, brushland, wetland, wet meadows, and 

fens (NPS 2006c).

The Upper Mississippi River National Wildlife and Fish Refuge lies about 30 mi (48 km) 

southeast of the PINGP 1 and 2 site and spans 261 mi (420 km) of the Mississippi River 

and 240,220 ac (97,213 ha) of land beginning at the confluence of the Chippewa River 

near Wabasha, Minnesota and continuing to Rock Island, Illinois (FWS Undated a; 

Undated b). The refuge encompasses part of the Mississippi flyway and constitutes the 

largest river refuge in the continental United States (FWS Undated b). The refuge 

contains 167 known bald eagle nests and 5,000 blue heron (Ardea herodias) and great 
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2-37

white egret (Ardea alba) nests in 15 colonies as well as over 48,000 ac (19,400 ha) of 

marsh habitat (FWS Undated a). The FWS focuses on restoration of riverine habitat and 

native grass prairie, bank stabilization, island building, and bird and waterfowl nest 

counts and surveys in their management of the refuge (FWS Undated b).

PINGP 1 and 2-associated transmission lines cross five wildlife refuges, wildlife 

management areas, and parks. The Red Rock 2 line crosses Gores Pool #3 Wildlife 

Management Area, a 6449-ac (2610-ha) area in Goodhue County that consists of 

floodplain forest and backwater marshes and contains a migratory bird refuge; Lost 

Valley Scientific and Natural Area, a 200-ac (81-ha) bluff prairie in Washington County 

that is one of the few sites in the state containing rock sandwort (Minuartia michauxii); 

and the northern part of Cottage Grove Ravine Regional Park in Washington County 

(MNDNR 2008c; MNDNR 2008h; NMC 2008). The Blue Lake line crosses the Black Dog 

Unit of the Minnesota Valley National Wildlife Refuge and the Savage Fen Scientific and 

Natural Area, a 43-ac (17-ha) area in Scott County that consists of a unique wetland 

plant community that grows on moist peat substrate and is sensitive to disturbance 

(MNDNR 2008e; NMC 2008).

2.2.7 Threatened and Endangered Species

Tables 2-11 and 2-12 list aquatic and terrestrial species, respectively, that are 

threatened, endangered, or candidate species known to occur in Goodhue County, in 

which PINGP 1 and 2 are located, or Dakota, Washington, or Scott Counties, through 

which transmission line ROWs associated with PINGP 1 and 2 traverse. Table 2-11 also 

includes any aquatic species listed in Pierce County, WI, which lies on the opposing 

shore of the Mississippi River from PINGP 1 and 2.

2.2.7.1 Aquatic Species

The Higgins eye pearlymussel was Federally listed as an endangered species on June 

14, 1976 (41 FR 24064). The Higgins eye was never abundant, although the historical 

range is not completely known. It is currently found in the Upper Mississippi River above 

Lock and Dam 19, in the St. Croix, Wisconsin, and Rock Rivers, an estimated 50 percent 

from the historical range (FWS 2000a).

Higgins eye pearlymussel

Preferring medium to large rivers with firm substrate ranging from sand to boulders, the 

Higgins eye are typically found in large, stable, species-diverse mussel beds (FWS 

2000a; 2004a). Current velocities typical of Higgins eye habitat range from 0.5 to 1.5 fps 

(1.5 to 4.5 cm/s), and depths range from 3.3 to 19.7 ft (1-6 m) (FWS 2000a). Although 

no critical habitat is listed for the species, 14 Essential Habitat Areas (EHAs) have been 

designated for the Higgins eye: six in the Mississippi River, three in the St. Croix River, 

and one in the Wisconsin River (FWS 2004a). FWS (2008a) added four new Essential 

Habitat Areas far downriver in Pools 9, 11, 15, and 16.The closest EHA to PINGP 1 and 

2 is in the St. Croix river, just upstream of the junction with the Mississippi River, near 

Prescott, Wisconsin (FWS 2004a). 

To reproduce, male Higgins eyes release sperm into the water. As the females siphon 

water for food, they also take in the sperm to fertilize eggs in gill sacs (marsupia), where 

the fertilized eggs mature into glochidia, a larval stage. The ribbon-like mantle edge near 

the posterior of the female acts as a lure to attract fish; when the fish attack the mantle, 

glochidia are released into the water and attach to the gills of the host fish. If the 

glochidia successfully attach to fish gills, they can mature into juvenile mussels (typically 
Affected Environment

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three weeks, though a study at the Genoa National Fish Hatchery suggests that it may 

take up to six or seven weeks [DOI 2010]), excyst from the gills, settle to suitable 

substrate, and mature into adults. Some studies suggest glochidia remain in the 

marsupia through winter and are released in spring or summer. (FWS 2000a; FWS 

2004a)

Suitable fish hosts for the glochidia of the Higgins eye pearlymussel include freshwater 

drum (Aplodinotus grunniens), largemouth bass (Micropterus salmoides), smallmouth 

bass (Micropterus dolomieu), yellow perch (Perca falvescens), sauger (Stizostedion 

canadense), walleye (Stizostedion vitreum vitreum) and black crappie (Pomoxis 

nigromaculatus); marginal fish hosts include northern pike (Esox lucius), bluegill 

(Lepomis macrochirus), and green sunfish (Lepomis cyanellus) (FWS 2004a).

Currently, the major threat to the Higgins eye pearlymussel, like most other native 

mussels in the Upper Mississippi River, is the invasion of the zebra mussel. As 

described in Section 2.2.5, zebra mussels compete for food and space, and even 

colonize on native mussels. The subfamily Lampsilinae (to which the Higgins eye 

belongs) is one of the most sensitive groups of mussels to zebra mussels (FWS 2000a).

Researchers have not developed effective and practical measures to control zebra 

mussel populations without harming native aquatic organisms (WDNR 2004).

The creation of the lock and dam system in the Upper Mississippi River has resulted in 

pools replacing once-flowing water, and species of fish that serve as hosts to native 

mussel species are now restricted in their movements. In the case of the Higgins eye, it 

is possible that the damming of the Mississippi led to higher populations of the species in 

some pools, given the species’ propensity towards low velocity waters. However, some 

observations state that the population of Higgins eye has decreased since impoundment 

in other pools, possibly due to conditions such as increased sedimentation. Therefore it 

is uncertain how the changes to the Mississippi River have affected the Higgins eye 

populations. (FWS 2000a)

Other activities, such as dredging, the disposal of dredged material, channelization, and 

commercial navigation are all threats to the survival of native mussel species, including 

Higgins eye pearlymussel. There are few documented reports of the commercial harvest 

of Higgins eye. (FWS 2000a)

In 1993, the USACE began a consultation with the FWS under Section 7 of the 

Endangered Species Act of 1973 (ESA) for a project, the operation and maintenance of 

the 9-foot Navigation Project on the Upper Mississippi River. The Higgins eye 

pearlymussel was included in this consultation. In 2000, FWS issued a Biological 

Opinion (BO) (FWS 2000a), with a jeopardy determination for the Higgins eye. In the 

BO, FWS provided reasonable and prudent alternatives to allow for the project while 

offsetting adverse impacts to the species involved, including the alternative that USACE 

develop a Higgins’ eye pearlymussel relocation action plan, as well as conduct a study 

to control the spread of zebra mussels.

In 2002, USACE, in cooperation with the Mussel Coordination Team, an interagency 

team of biologists, issued a definite project report and environmental assessment for a 

relocation plan for the Higgins eye (USACE 2002), with a proposal to establish five new 

populations of the Higgins eye by moving adults from zebra mussel-infested areas into 

sections of the river that had no or low levels of zebra mussels, as well as raising 

juvenile mussels at hatcheries and stocking areas of the river (USACE 2002).
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A team including FWS, USACE, and the Mussel Coordination Team, selected an area 

within Pool 3, 0.5 mi (0.8 km) upstream of the PINGP 1 and 2 intake structure for one of 

the relocation sites. In the 2002 environmental assessment (USACE 2002), the USACE 

states that this site had shown good recovery of mussels after the relocation of 100 adult 

Higgins eye by MNDNR, WDNR, and FWS. In addition, the location was identified as a 

good relocation site based on the 2000 Minnesota 305(b) water quality status report, 

which listed Pool 3 as “full support” for aquatic life (USACE 2002). As of 2008, Higgins 

eye were found to still be present at this site. Releases of sub-adult Higgins eye have 

also been released at other locations as a effort to offset adverse impacts of zebra 

mussels elsewhere in the Mississippi and St. Croix Rivers (DOI 2010). Over 4000 subadults have been relocated to the Sturgeon Lake section of Pool 3, as of the 2005 Status 

Report (Mussel Coordination Team 2005). The Mussel Coordination Team (2005) 

reported “good recovery” for Pool 3 subadults after conducting monitoring in 2003. Other 

sites have not had as positive results, such as Pool 4 (just downstream of Lock and Dam 

3, in which only 5 percent of the mussels were recovered; predation by carp could be the 

cause of the low success of the Pool 4 population (Mussel Coordination Team 2005).

The winged mapleleaf (Quadrula fragosa), specie of mussel, is Federally listed as an 

endangered species. Historically found in 34 rivers and 12 states, the winged mapleleaf 

has been limited to one population that is known to be reproducing, on a 12.4-mi stretch 

of the St. Croix River, 44 river miles upstream of the confluence with the Mississippi

(FWS 2000a). Additionally, there are populations in the Ouachita and Saline Rivers of 

Arkansas and the Bourbeuse River in Missouri (FWS 2004b). The FWS lists the winged 

mapleleaf as endangered within Washington County. It is also state-listed as 

endangered by Minnesota in Dakota and Washington Counties (counties crossed by 

PINGP 1 and 2 transmission lines), and by Wisconsin in Pierce County (the county 

located across the Mississippi River from PINGP 1 and 2) (FWS 2008d; MNDNR 

2008b). The winged mapleleaf is not known to be present in the vicinity of PINGP 1 and 

2 or associated transmission line ROWs.

Winged mapleleaf

The spectaclecase (Cumberlandia monodonta) and sheepnose (Plethobasus cyphyus) 

are considered candidates for listing by FWS. In Minnesota, populations of 

spectaclecase exist in the Mississippi and St. Croix Rivers and Rush Creek; populations 

of sheepnose (also called bullhead) occur in the Mississippi and St. Croix Rivers (FWS 

2002a; 2002b). Neither species of mussel is known to be present in the vicinity of PINGP 

1 and 2 or associated transmission line ROWs.

Spectaclecase and Sheepnose

The paddlefish (Polyodon spathula) is state-listed by both Minnesota and Wisconsin as 

threatened. Reaching weights of 50 lb (23 kg) in Minnesota, topping 150 lb (68 kg)

farther south, the paddlefish feeds on plankton, is found in larger rivers and river lakes, 

and migrates into streams to spawn (Phillips et al. 1982). Human activities including 

water pollution, channelization, dredging, damming rivers, and over-fishing have reduced 

the numbers of paddlefish in the Mississippi River drainage (Schmidt 2004). Sturgeon 

Lake once provided habitat for the paddlefish, but sediment deposition reduced the 

suitability of the area for the fish (Schmidt Undated). However, individuals are 

occasionally found in the vicinity of PINGP 1 and 2 by Xcel Energy biologists.

Paddlefish
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State-listed Mussels

Five mussel species listed under the Minnesota Endangered Species Statute are known 

to occur in the Mississippi River within the vicinity of PINGP 1 and 2: the rock 

pocketbook (Arcidens confragosus), the black sandshell (Ligumia recta), the washboard 

(Megolonaias nervosa), the hickory nut (Obovaria olivaria), and the wartyback (Quadrula 

nodulata). These, as well as 14 other non-listed mussel species were identified as 

occurring along the Minnesota bank of the Mississippi River Pool 3 during a survey that 

was conducted in June of 2009 (Ecological Specialists 2009). The Minnesota-listed

mucket (Actinonaias ligamentina) and butterfly (Ellipsaria lineolata) were not found 

during this survey, though they have been historically found in the vicinity of the PINGP 

1 and 2 site. These two mussel species are considered rare in Pool 2, but have been 

recorded in small populations within the past 25 years (Ecological Specialists 2009).

Threats to these mussel species are typical of the threats to mussels in the Mississippi

River, generally, and include impoundment, dredging, and zebra mussel infestation. 
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Table 2-11. Listed Aquatic Species. The species below are Federally listed, 

Minnesota-listed, and/or Wisconsin-listed as threatened, endangered, or 

candidate species. These species may occur on the PINGP 1 and 2 site, within 

the Upper Mississippi River Basin, or within the transmission line rights-of-way.

Scientific Name Common Name(a) Federal 

Status(b) State Status(c)

Fish

Acipenser fulvescens lake sturgeon - MSC; WSC 

Alosa chrysochloris skipjack herring - MSC; WE 

Ammocrypta asprella crystal darter - MSC; WE 

Anguilla rostrata American eel - WSC

Clinostomus elongatus redside dace - WSC

Cycleptus elongatus blue sucker - MSC; WT 

Etheostoma asprigene mud darter - WSC 

Etheostoma clarum western sand darter - WSC

Fundulus diaphanus banded killifish - WSC

Hiodon alosoides goldeye - WE

Ictiobus niger black buffalo - MSC; WT 

Macrhybopsis aestivalis shoal chub - WT

Macrhybopsi storeiana silver chub - WSC

Moxostoma carinatum river redhorse - WT

Notropis amnis pallid shiner - MSC; WE 

Notropis texanus weed shiner - WSC

Opsopoeodus emiliae pugnose minnow - WSC

Polyodon spathula paddlefish - MT; WT 

Mussels

Actinonaias ligamentina mucket - MT 

Alasmidonta marginata elktoe - MT; WSC 
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Scientific Name Common Name(a) Federal 

Status(b) State Status(c)

Arcidens confragosus rock pocketbook - ME; WT

Cumberlandia monodonta spectaclecase C MT; WE 

Cyclonaias tuberculata purple wartyback - MT; WE 

Ellipsaria lineolata butterfly - MT; WE 

Elliptio crassidens elephant-ear - ME; WE 

Elliptio dilatata spike - MSC 

Epioblasma triquetra snuffbox - MT; WE 

Fusconaia ebena ebonyshell - ME; WE 

Lampsilis higginsi Higgins eye E ME; WE 

Lampsilis teres yellow/slough sandshell - ME; WE 

Lasmigona costata fluted-shell - MSC 

Ligumia recta black sandshell - MSC 

Megalonaias nervosa washboard - MT; WSC 

Obovaria olivaria hickory nut - MSC 

Plethobasus cyphyus sheepnose (bullhead) C ME; WE

Pleurobema sintoxia (formerly P. 

coccineu) 

round pigtoe - MT; WSC 

Quadrula fragosa winged mapleleaf E ME; WE

Quadrula metanevra monkeyface - MT; WT 

Quadrula nodulata wartyback - ME 

Tritogonia verrucosa pistolgrip (buckhorn) - MT; WT 

(a) Common names indicated by parentheses are those listed by the Wisconsin Department of Natural 

Resources

(b) C = Candidate; E = Federally endangered; T = Federally threatened; - = No listing

(c) ME = Minnesota endangered; MT = Minnesota threatened; MSC = Minnesota species of concern; WE = 

Wisconsin endangered; WT = Wisconsin threatened; WSC = Wisconsin species of concern

Sources: FWS 2008a; MNDNR 2008b; NMC 2008; WDNR 2008
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2.2.7.2 Terrestrial Species

Two Federally listed species, the dwarf trout lily (Erythronium propullans) and the prairie 

bush clover (Lespedeza leptostachya), potentially occur on or in the vicinity of the 

PINGP 1 and 2 site or along the in-scope transmission line ROWs. One state-listed 

species, the peregrine falcon (Falco peregrinus), is known to occur in the vicinity of 

PINGP 1 and 2.

The dwarf trout lily is Federally and Minnesota State-listed as endangered. The species 

is a spring ephemeral wildflower endemic to Minnesota and only occurs in Rice, 

Goodhue, and Steele Counties within the Straight, Cannon, Little Cannon, and North 

Fork Zumbro Rivers and Prairie Creek (FWS 2008c; Sather 1990a). Dwarf trout lily is 

found on north-facing slopes of maple- and basswood-dominated forests as well as elmand cottonwood-dominated floodplains (FWS 2008c). Leaves are tapered and slightly 

mottled in color, and small, pale pink, four- to six-petal flowers are sparsely dispersed 

(Sather 1990a). The plant’s rarity is attributed to its slow rate of reproduction as only a 

small percentage (one-tenth) of plants produce flowers each spring (Sather 1990a). The 

species generally reproduces vegetatively by sending out underground runners that bear 

new bulbs (Sather 1990a; FWS 2008c). Neither the FWS nor the MNDNR listed this 

species as present on or in the vicinity of the PINGP 1 and 2 site in their correspondence 

with the NRC regarding the proposed license renewal of PINGP (FWS 2008b; MNDNR 

2008b).

Dwarf Trout Lily

The prairie bush clover is Federally and Minnesota State-listed as threatened. The 

species is a slender-leaved legume in the pea family with pink to cream flowers that 

bloom in July (Sather 1990b). The prairie bush clover is endemic to the Midwest and 

only occurs in Minnesota, Wisconsin, Iowa, and Illinois tall-grass prairie habitat within the 

upper Mississippi River Valley (FWS 2000b). In 1990, about 100 known prairie bush 

clover sites existed, and by 2000, fewer than 40 known sites remained (FWS 2000b; 

Sather 1990b). Loss of prairie habitat is attributed to this species’ decline (FWS 2000b). 

Neither the FWS or MNDNR listed this species as present on or in the vicinity of the 

PINGP 1 and 2 site in their correspondence with the NRC regarding the proposed 

license renewal of PINGP (FWS 2008b; MNDNR 2008b).

Prairie Bush Clover

The peregrine falcon was removed from Federal listing in August 1999 but continues to 

be threatened at the State level. Adult birds have a bluish-black head and wings, are 14 

to 19 in. (36 to 48 cm) tall, and have a wingspan of 39 to 43 in. (99 to 109 cm) (Cornell 

2003). Peregrine falcons nest from April to July on high cliffs and bluffs and on tall city 

buildings along the North Shore of Lake Superior and the Mississippi River in the 

southeastern portion of the State (MNDNR 2008d). Females lay 2 to 5 eggs, which hatch 

in 28 to 29 days, and young leave the nest within 6 to 9 weeks of hatching (MNDNR 

2008d). Peregrine falcons prey on ducks, pigeons, and other birds as well as small 

mammals and insects (MNDNR 2008d). Approximately 36 breeding pairs nest in 

Minnesota (MNDNR 2008d).

Peregrine Falcon

The PINGP Unit 1 containment building has a nest box, in which a breeding pair has 

nested consistently since 1997 (NMC 2008). The pair is usually first observed in March, 

and young fledge by July; NSP has recorded 31 falcons that have fledged since 1997 

(NMC 2008). NSP has designated staff members to monitor the peregrine falcons on 
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site in conjunction with the MNDNR and the University of Minnesota Raptor Center. NSP 

educates its staff members on the falcons to ensure the safety of the birds in the event 

that specialists would need to be notified, such as if a fledgling fell from the nest and 

required veterinary care.

The bald eagle (Haliaeetus leucocephalus) is a species of special concern in the State of 

Minnesota. Bald eagles mature at 4 to 5 years of age and average 8 to 9 lbs (kg) for 

males and 10 to 14 lbs (kg) for females with a 6 to 7.5 ft (m) wingspan (MNDNR 2008a). 

The FWS formally removed the bald eagles from the Federal List of Endangered and 

Threatened Wildlife effective August 8, 2007 though the species continues to be 

protected under the Bald and Gold Eagle Protection Act and the Migratory Bird Treaty 

Act (72 FR 37346). Two bald eagle nests are known to occur near the PINGP 1 and 2 

site, though no bald eagle nests have been observed on PINGP 1 and 2 property (NMC 

2008). A nest is located on the Vermillion River just south of the PINGP 1 and 2 site, and 

a nest is located approximately 2 mi (km) upstream of Lock and Dam 3 on the 

Mississippi River (NMC 2008). The Minnesota population continues to grow. According 

to statewide bald eagle surveys conducted by MNDNR in conjunction with the FWS and 

USGS, a 28 percent increase in active nests was observed between 2000 and 2005 

(MNDNR 2006a).

Bald Eagle

The trumpeter swan (Cygnus buccinator) is migratory bird that is Minnesota State-listed 

as threatened. Adult trumpeter swans have white plumage and black bills and feet. 

Adults are 4 to 5 ft (m) tall, have a wingspan up to 8 ft (m), and weigh 20 to 30 lbs (kg) 

(MNDNR 2008f). Swans nest in marshy areas beginning at 3 to 4 years of age, and 

females lay clutches of 5 to 7 eggs in late April, which hatch within 33 to 37 days 

(MNDNR 2008f). Young swans generally fly at 14 to 17 weeks of age (MNDNR 2008f). 

The MNDNR Nongame Wildlife Program has been involved in restoration efforts of the 

Minnesota flock since the 1980s, and the population has gone from virtually extinct to 

more than 2000 individuals as of 2004 (MNDNR 2008g). The MNDNR did not list this 

species as present on or in the vicinity of the PINGP 1 and 2 site in their correspondence 

with the NRC regarding the proposed renewal of PINGP 1 and 2 (MNDNR 2008b).

Trumpeter Swan
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Table 2-12. Listed Terrestrial Species. The species below are Federally listed, 

Minnesota-listed, or both, as threatened, endangered, or candidate species. 

These species may occur on the PINGP 1 and 2 site, within the Mississippi 

River, or within the transmission line ROWs.

Scientific Name Common Name Federal 

Status(a)

State 

Status(b) Habitat

Reptiles and Amphibians

Acris crepitans northern cricket 

frog 

- ME ponds and streams with 

submerged vegetation

Clemmys 

insculpta 

wood turtle - MT large rivers with sandy 

substrate

Coluber 

constrictor 

blue racer - MSC riparian areas; swamps

Crotalus horridus timber rattlesnake - MT forested areas; swamps

Emydoidea 

blandingii 

Blanding’s turtle - MT shallow ponds; marshes; 

swamps

Pituophis catenifer gopher snake - MSC woodlands; agricultural 

areas; prairie

Insects

Aflexia rubranura red tailed prairie 

leafhopper 

- MSC mesic prairie

Speyeria idalia regal fritillary - MSC tall-grass prairie; 

meadows; floodplain 

forest edges

Birds

Buteo lineatus red-shouldered 

hawk

- MSC deciduous and deciduousconifer forest; swamps

Cygnus buccinator trumpeter swan - MT prairie; marshes; shallow 

lakes

Dendroica cerulea cerulean warbler - MSC old-growth deciduous 

floodplain forest

Falco peregrinus peregrine falcon - MT grasslands; meadowlands

Haliaeetus 

leucocephalus 

bald eagle DL MSC forested areas near open 

water

Lanius 

ludovicianus 

loggerhead shrike - MT thicketed areas; meadows 

bordered by trees

Sterna forsteri Forster’s tern - MSC marshes

Wilsonia citrina hooded warbler - MSC heavily forested areas
Affected Environment

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Scientific Name Common Name Federal 

Status(a)

State 

Status(b) Habitat

Mammals

Perognathus 

flavescens 

plains pocket 

mouse

- MSC sparsely vegetated areas

Plants

Agalinis auriculata eared false 

foxglove 

- ME mesic tall-grass prairie

Aristida 

tuberculosa 

sea-beach 

needlegrass 

- MSC prairie

Arnoglossum 

plantagineum 

tuberous Indianplantain - MT prairie

Asclepias 

amplexicaulis 

clasping milkweed - MSC prairie; sand barrens

Asclepias 

sullivantii 

sullivant's milkweed - MT prairie; sedge meadows

Besseya bullii kitten-tail - MT prairie

Botrychium 

oneidense 

blunt-lobed 

grapefern 

- ME moist, acidic woods; 

swamps

Botrychium 

rugulosum 

St. Lawerence 

grapefern 

- MT open fields; secondary 

forests

Carex sterilis sterile sedge - MT lowland forest

Cirsium hillii Hill's thistle - MSC prairie

Cladium 

mariscoides 

twig-rush - MSC sand dunes

Cristatella jamesii James' polanisia - ME river banks; prairie

Cypripedium 

candidum 

small white Lady'sslipper - MSC lowland forest; prairie

Eleocharis 

rostellata 

beaked spike-rush - MT wet fens; shores

Eryngium 

yuccifolium 

rattlesnake-master - MSC prairie

Erythronium 

propullans 

dwarf trout lily E ME deciduous forest 

floodplains

Hudsonia 

tomentosa 

beach-heather - MSC sand barrens

Juniperus 

horizontalis 

creeping juniper - MSC cliffs; sand barrens; sand 

dunes

Lespedeza 

leptostachya 

prairie bush clover T MT prairie
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Scientific Name Common Name Federal 

Status(a)

State 

Status(b) Habitat

Lesquerella 

ludoviciana 

bladder pod - ME coastal bluffs; prairie

Minuartia 

dawsonensis 

rock sandwort - MSC disturbed slopes; mesic 

forest openings; prairie

Oenothera 

rhombipetala 

rhombic-petaled 

evening primrose 

- MSC prairie; sand barrens

Opuntia 

macrorhiza 

plains prickly pear - MSC grassy woodlands; 

coniferous forests

Orobanche 

fasciculata 

clustered 

broomrape 

- MSC prairie

Panax 

quinquefolius 

American ginseng - MSC upland forests

Rhynchospora 

capillacea 

hair-like beak-rush - MT sand dunes

Scirpus clintonii Clinton's bulrush - MSC open forested areas; 

wetlands

Scleria verticillata whorled nut-rush - MT marshes; bogs

Trillium nivale snow trillium - MSC forested areas; floodplain 

riverbanks

Valeriana edulis 

ciliata 

valerian - MT lowland forest; prairie

(a) DL = Delisted; E = Federally endangered; T = Federally threatened; - = No listing

(b) ME = Minnesota endangered; MT = Minnesota threatened; MSC = Minnesota species of concern

Sources: FWS 2008a; MNDNR 2008b; NMC 2008

2.2.8 Socioeconomic Factors

This section describes current socioeconomic factors that have the potential to be 

directly or indirectly affected by changes in PINGP 1 and 2 operations. PINGP 1 and 2 

and the communities that support it can be described as a dynamic socioeconomic 

system. The communities provide the people, goods, and services required to operate 

PINGP 1 and 2. PINGP 1 and 2 operations, in turn, create the demand and pay for the 

people, goods, and services in the form of wages, salaries, and benefits for jobs and 

dollar expenditures for goods and services. The measure of the communities’ ability to 

support the demands of PINGP 1 and 2 depends on their ability to respond to changing 

environmental, social, economic, and demographic conditions.

The socioeconomics region of influence (ROI) is defined as the areas in which PINGP 1 

and 2 employees and their families reside, spend their income, and use their benefits, 

thereby affecting the economic conditions of the region. The PINGP 1 and 2 ROI 

consists of a three-county area (Goodhue and Dakota Counties in Minnesota and Pierce 

County in Wisconsin)
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where approximately 83 percent of PINGP 1 and 2 employees reside as well as the 

PIIC. The following sections describe the housing, public services, offsite land use, 

visual aesthetics and noise, population demography, and economy in PINGP 1 and 2’s 

ROI.

NSP employs a permanent workforce of approximately 685 employees (NMC 2008). 

Approximately 83 percent live in Goodhue County and Dakota County, Minnesota, and 

Pierce County, Wisconsin (Table 2.13). The remaining 17.2 percent of the workforce are 

divided among 21 counties in Minnesota and Wisconsin with numbers ranging from 1 to 

47 employees per county. Given the residential locations of PINGP 1 and 2 employees, 

the most significant impacts of plant operations are likely to occur in Goodhue County,

Dakota County, and Pierce County. Therefore, the socioeconomic impact analysis in 

this SEIS will focus on the impacts of PINGP 1 and 2 on these three counties.

Table 2-13. PINGP 1 and 2 Employee Residence by County

County Number of Employees Percentage of Total

Goodhue, MN 329 48

Dakota, MN 139 20

Pierce, WI 99 15

Other 118 17

Total 685 100

Source: NMC 2008

Refueling outages at PINGP 1 and 2 generally occur at 20-month intervals. During 

refueling outages, site employment increases by as many as 925 workers for 

approximately 45 to 90 days (NMC 2008). Most of these workers are assumed to be 

located in the same geographic areas as the permanent PINGP 1 and 2 staff.

2.2.8.1 Housing

Table 2-14 lists the total number of occupied and vacant housing units, vacancy rates, 

and median value in the three-county ROI. According to the 2000 Census, there were 

over 165,000 housing units in the socioeconomic region, of which approximately 

161,000 were occupied. The median value of owner-occupied units ranged from 

$116,000 in Goodhue County to $152,400 in Dakota County. Goodhue County has the 

highest vacancy rate (5.0 percent), followed by Pierce County (3.5 percent), and then 

Dakota County (1.9 percent). (USCB 2000)

By 2007, the estimated number of housing units within the three counties grew by 

approximately 14.2 percent. In Goodhue County, the number of housing units grew by 

10.9 percent to an estimated 19,830 units. In Dakota County the number of housing 

units grew by 14.6 percent to an estimated 153,326 units. In Pierce County, the number 

of housing units grew by 13.8 percent to an estimated 15,354 units. (USCB 2007)
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Table 2-14. Housing in Goodhue and Dakota Counties, Minnesota, and Pierce 

County, Wisconsin and the Region

Goodhue Dakota Pierce Region

2000

Total 17,879 133,750 13,493 165,122

Occupied housing 

units 16,983 131,151 13,015 161,149

Vacant units 896 2,599 478 3,973

Vacancy rate (percent) 5.0 1.9 3.5 2.4

Median value (dollars) 116,000 152,400 123,100 130,500

2007(a)

Total 19,830 153,326 15,354 188,510

Occupied units 18,438 146,728 14,706 179,872

Vacant units 1,392 6,598 648 8,638

Vacancy rate (percent) 7.0 4.3 4.2 4.6

Median value (dollars) 192,100 246,800 203,600 214,167

(a)Housing values for 2007 are estimates based on 2005-2007 American Community Survey 3-

Year Estimates, U.S. Census Bureau

Sources: USCB 2000; USCB 2007

2.2.8.2 Public Services

This section presents a discussion of public services including water supply, education, 

and transportation.

Because approximately 83 percent of workers at PINGP 1 and 2 reside in Goodhue and 

Dakota Counties, Minnesota, and Pierce County, Wisconsin, the discussion of public 

water supply systems is limited to these counties. In Table 2-15, information about 

major municipal water suppliers in the three counties, their permitted capacities and/or 

maximum design yields, reported annual peak usage, and population served are 

presented. The primary source of potable water in the vicinity of the PINGP 1 and 2 is 

ground water (NMC 2008).

Water Supply

Goodhue County tries to balance the county’s natural resources, environmental habits, 

and growth to achieve long-term economic and ecological sustainability. Erosion control 

and storm water issues are the greatest concern to watershed impacts. Planning 

officials are concerned with agricultural and household contaminants getting into the 

ground water and the potential impact this could have on surface water (Goodhue 

County 2004). 

Dakota County is concerned about projected population growth through 2025 and the 

impact this growth will have on the availability of ground water and the effect this could 

have on surface water resources, which are dependent on ground water (Dakota County 

2005).

Approximately 70 percent of Wisconsin’s private residents and most public water 

systems use ground water for their water source. Wisconsin implemented a program in 
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1999 designed to develop capacity for these water systems. A capacity evaluation is 

required for all new water supply systems.

Most of the PIIC’s water is supplied by the PIIC’s central water system. This system 

serves all homes immediately adjacent to PINGP 1 and 2, the Treasure Island Resort 

and Casino, Dakota Station and government offices. The PIIC’s average winter daily 

use is approximately 100,000 gpd (379,000 liters per day [LPD]), and their average 

summer daily use is approximately 370,000 gpd (1,401,000 LPD). Treasure Island has 

480 sleeping rooms, which typically increase summer water use by approximately 

370,000 gpd (1,401,000 LPD). The total expected peak daily usage is approximately 

740,000 gpd (2,800,000 LPD). The central water system draws from the Mt. SimonHinckley aquifer at a depth of 500 ft (150 m). (PIIC 2008)

The newer homes on the PIIC’s Upper Island land, which are located about 3 mi (5 km)

from the PINGP 1 and 2 site, have individual wells. These wells draw from the Mt.

Simon-Hinckley aquifer at about 180 ft (55 m). The 47 proposed additional homes, 

which would be located about 2 mi (3.2 km) from the PINGP 1 and 2 site, may also use

individual wells. (PIIC 2008)

PINGP 1 and 2 are located in Red Wing School District 256, which had an enrollment of 

approximately 2,900 students in the 2007-2008 school year (MDE 2007; 2008a). 

Including School District 256, Goodhue County has 4 public school districts with over 

7,000 enrolled students (MDE 2008a, MDE 2008b). Dakota County has 8 public school 

districts (MDE 2008a). Total enrollment in Dakota County public schools in the 2007-

2008 school year was approximately 74,500 students (MDE 2008b). Pierce County, 

Wisconsin, has 6 public school districts with a total enrollment of 7452 students (WDPI 

2009).

Education

Children from the PIIC attend Red Wing public schools or private schools. Additionally, 

the PIIC offers its members tutoring services, Dakota language classes, summer school, 

GED preparation, and assistance with college applications at its Learning Center, 

located on Prairie Island (PIIC 2008).
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Table 2-15. Major Public Water Supply Systems (in million gallons 

per day [gpd])

Water Supplier a

Water 

Source(a)(b)

Peak Annual 

Withdrawal

(2004 – 2007)(c)

Permitted Annual 

Withdrawal(b)

Population 

Served(c)

Goodhue County, Minnesota 

City of Cannon Falls GW 206 1,250 3,800

City of Kenyon GW 65 144 1,700

City of Pine Island GW 119 332 2,300

City of Red Wing GW 624 6,750 16,100

City of Wanamingo GW 35 120 1,000

City of Zumbrota GW 179 660 3,000

Dakota County, Minnesota 

City of Apple Valley GW 2,640 57,000 48,000

City of Burnsville GW 2,980 57,800 62,200

City of Eagan GW 3,350 89,700 66,700

Empire Township GW 81 270 1,300

City of Farmington GW 810 8,000 18,000

City of Hastings GW 1,000 7,000 21,600

City of Inver Grove Heights GW 1,150 10,000 33,200

City of Lakeville GW 2,550 48,000 52,000

City of Rosemount GW 944 11,500 21,000

City of South St. Paul GW 1,240 9,600 20,300

Pierce County, Wisconsin

Ellsworth Waterworks GW 101 368 2,800

Prescott Waterworks GW 171 1,310 4,000

River Falls Waterworks GW 396 2,600 12,600

Spring Valley Waterworks GW 38 258 1,300

(a) GW = Ground water; SW = surface water

(b) EPA 2008b

(c) MNDNR 2008 for Minnesota; NMC 2008 for Wisconsin.

Sources: EPA 2008b; MNDNR 2008; NMC 2008.

Plant workers that commute from northeastern, southern, and central Dakota County 

may take U.S. Highway (US) 61 East (1) to the intersection of County Road 19, (2) 

continue to County Road 31, which connects with County Road 18, or (3) continue east 

on US 61 to County Road 18. For each route, workers must travel north on County 

Road 18 to Sturgeon Lake Road and then proceed east approximately 0.5 mi (0.8 km)

on Sturgeon Lake Road, turn south onto the plant access road, and proceed to the plant 

entrance just past the intersection of Wakonade Drive. Plant workers that commute from 

the southern and eastern portions of Dakota County will most likely travel to PINGP 1 

and 2 via US 61.

Transportation
Affected Environment

2-52

Workers that commute from Pierce County may take US 63 and cross into Goodhue 

County at Red Wing and continue to US 61. Pierce County employees may also cross 

the Mississippi River via US 10, which connects with US 61 South via State Road 316. 

Employees would then travel southeast to Goodhue County Road 68 and then northeast 

to County Road 18. Commuters may also access County Road 18 via County Road 54 

in Hastings to County Road 68 East.

Table 2.16 lists commuting routes to PINGP 1 and 2 and average annual daily traffic 

(AADT) volumes. The AADT values represent traffic volumes for a 24-hour period 

factored by both day of week and month of year. Table 2.16 data indicates that current 

AADTs are below maximum capacities for the roads leading to PINGP 1 and 2.

Because Sturgeon Lake Road is the only access road to the PIIC and PINGP 1 

and 2, the PIIC is concerned about PINGP 1 and 2-related traffic impacts. Many 

PINGP 1 and 2 employees exit the plant in the afternoon via Wakonade Drive, 

which had been limited to northbound out-going traffic from the PINGP 1 and 2 

site, and proceed to Sturgeon Lake Road and through the PIIC reservation, 

rather than accessing Sturgeon Lake Road directly from the plant access road. 

This traffic volume was cause for concern to the PIIC because the section of 

Sturgeon Lake Road that runs through the reservation has more pedestrian, 

bicycle, and small motorized cart traffic than the rest of the road. (PIIC 2009) 

Wakonade Drive is now two way to PINGP and the traffic through the reservation 

should be reduced. (NSP 2010)

In addition to the traffic created by 685 full-time employees of PINGP 1 and 2 

(and as many as 925 additional workers during outages), daily traffic on Sturgeon 

Lake Road includes approximately 102 Tribal government employees, and as 

many as 16,000 Treasure Island guests, and 1,500 Treasure Island employees. 

(PIIC 2009)

2.2.8.3 Offsite Land Use

Offsite land use conditions in Goodhue County, Dakota County, and Pierce County are 

described in this section. In addition to property taxes, Goodhue and other counties in 

the vicinity of PINGP 1 and 2 also receive revenue from sales taxes and fees paid by 

NSP and its employees residing in the region. Changes in the number of workers at 

PINGP 1 and 2 and tax payments to local jurisdictions could affect land use conditions in 

these counties. PINGP 1 and 2 are located in northeastern Goodhue County. Dakota 

County and Pierce County are located north and northeast of Goodhue County along the 

Mississippi River.

Although Goodhue County remains largely undeveloped, the county’s population has 

experienced some growth (see Section 2.2.8.5) and State and local planning officials 

expect the county to grow another 7 percent by 2010. The majority of residential, 

commercial, and industrial development has occurred along two highway corridors, US 

61 and US 52. Regional planners estimate that, as the Minneapolis-St. Paul area 

continues to expand and commuting distances increase, growth will continue in this 

region (Goodhue County 2004). 

Goodhue County has a comprehensive land use plan and zoning and subdivision 

ordinances to guide development. The ordinances promote the public health, safety, 

and general welfare of residents; protect agricultural land from urban sprawl; and provide 

a basis for orderly development. The ordinances require building permits, conditional 
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use permits, plat development, zoning district controls, and variance requests; however, 

the county has no formal growth control measures. 

Table 2-16. Major Commuting Routes in the Vicinity of the Prairie Island Nuclear 

Generating Plant and 2007 Average Annual Daily Traffic (AADT) Counts

Roadway and Location Road/Highway Capacity 

(vehicles per day)

Annual Average Daily 

Traffic (AADT)(a)

County Road 18 (just north of intersection 

with Sturgeon Lake Road) 12,000 6,000

County Road 18 Segment (south of 

intersection with Sturgeon Lake Road and 

north of County Road 19)

12,000 6,300

County Road 18 (between County Road 

19 and County Road 46, Mt. Carmel 

Road)

12,000+ 6,200

Sturgeon Lake Road 20,000 10,500

County Road 19 (between County Road 

18 and U.S. Highway 61) 5,000 315

County Road 31 (between County Road 

18 and U.S. Highway 61) 10,000 530

County Road 7 (just south of intersection 

with U.S. Highway 61) N/A 580

U.S. Highway 61 (between County Road 

18 and County Road 19) 40,000 17,000

U.S. Highway 61 (between State Road 

316 and County Road 19) 40,000 11,200

(a) All AADTs represent traffic volume during the average 24-hour day during 2006.

Source: Mn/DOT 2007; NMC 2008

Dakota County is located south of Minneapolis-St. Paul and covers approximately 

370,000 ac (150,000 ha). The largest category of land use in Dakota County is 

agricultural. Land used for agriculture comprises approximately 65 percent of the county 

area. Commercial, industrial, and residential land use covers 22 percent. Open water, 

parks, and public land cover the remaining 15 percent (Dakota County 1999). The 

majority of the county population is concentrated in the northern third of the county.

Dakota County, Minnesota

As the cities of Minneapolis-St. Paul have grown, residential development has expanded 

to neighboring counties, such as Dakota County, and residents commute to the cities for 

employment (Dakota County 1999). In general, land use decision-making occurs at the 

city and township level through zoning and the influence of land use planning at the 

regional level (Dakota County 2005). 
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Pierce County, located east of Minneapolis-St. Paul and northeast of PINGP 1 and 2, 

covers approximately 380,000 ac (154,000 ha), and is currently developing a countywide comprehensive plan (Pierce County 2006). Land development activities are guided 

by the County’s municipalities through the use of local zoning and subdivision 

regulations until the county plan is complete.

Pierce County, Wisconsin

Pierce County planners report that, between 2002 and 2005, approximately 8 percent of 

the county’s farmland was converted from agriculture to other uses. Planners estimate 

that, by 2025, the county may need to accommodate over 7,000 ac (280 ha) of new 

residential, commercial, and industrial land use along with additional acreage needed for 

infrastructure, parks, community facilities, and similar uses (Pierce County 2006).

Most of the PIIC’s lands are held in Trust, for the benefit of the PIIC, by the U.S.

Government. Trust status means that the land is protected from State or local 

jurisdiction, including taxation, can never be sold, and is forever available for the 

common benefit of the Tribe. Regulations governing the transfer of land into Trust can 

be found at 25 CFR 151. (PIIC 2008)

Prairie Island Indian Community

Past Congressional actions (i.e., the General Allotment Act or the Dawes Act, in effect 

from 1887 until 1934), resulted in the loss of Indian lands to non-Indians because of 

foreclosure due to the inability to pay property taxes on land allotted to individual 

Indians. During the 47 years that the Allotment Act was in effect, approximately 

90,000,000 ac (36,400,000 ha) of Treaty-protected land or about two-thirds of the 1887 

national tribal land base was lost. The Indian Reorganization Act (or Wheeler-Howard 

Act), passed by Congress in 1934, slowed the practice of assigning tribal lands to 

individual tribal members and reduced the loss of Indian land holdings. (PIIC 2008)

In addition to its Trust land, the PIIC also owns approximately 685 ac (280 ha) of land 

that is not in Trust and is therefore subject to State and local land use jurisdiction. The 

Mount Frontenac Golf Course (426 ac [170 ha]) is not in Trust and the Tribe does not 

plan to request that the U.S. Government, through the Bureau of Indian Affairs, take the 

land into Trust. The PIIC Tribal Council is in the process of developing Fee-to-Trust 

applications for the remaining 259 ac (105 ha) of land in order to develop additional 

home sites. (PIIC 2008)

As mentioned previously, the PIIC’s land (with the exception of the 685 ac [280 ha] not in 

Trust) are not subject to State or local land use jurisdiction. The PIIC is therefore free to 

develop its own land-use management policies and plans for Trust lands. Some land 

management projects include the following (PIIC 2008):

Native Prairie Restoration Project

The prairie restoration project has restored over 200 ac (80 ha) of native 

prairie. The restored prairies serve several important functions: they are 

an important food source for the Tribe’s Buffalo herd; they are a potential 

source of medicinal and culturally important plants; they protect the 

Mississippi River by reducing agricultural and sediment run-off; and they 

provide important habitat for birds and other wildlife. Since each prairie 

planting has its own personality, proper management is the key to 

maintaining a healthy prairie. The Tribe is in the process of creating a 

comprehensive prairie management plan to guide management practices 
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that will allow the tribe to create and maintain healthy diverse prairies in 

the future. (PIIC 2008)

Wild Rice Re-seeding Project

Wild rice is culturally significant to the Prairie Island Indian Community 

and an important food source for many waterfowl species found near 

Prairie Island. For these reasons, the Tribe has been re-establishing wild 

rice beds since 2001. To date, over 30 ac (12 ha) of wild rice have been 

seeded in wetlands along the Mississippi River. This project will be 

continued until the wild rice plants are self-sustaining. (PIIC 2008)

Water Quality Monitoring

The Prairie Island Indian Community has been conducting its own water 

quality monitoring since 1999. The Tribe has collected water quality data 

for the lakes, rivers, sloughs, and backwaters (i.e., habitats) adjacent to 

and within the study area (i.e., the lands of the Prairie Island Indian 

Community). Current studies include water quality monitoring, 

macroinvertebrate surveys, aquatic plant surveys, sediment quality 

monitoring, and shoreline habitat/land use surveys. This data will be 

useful in determining the current health of the lakes, river, and wetlands 

and determining the viability of re-establishing freshwater fish and other 

aquatic species. (PIIC 2008)

Source Water Protection Plan

The Tribe is currently developing a Source Water Protection Plan (SWPP) 

to ensure the safe supply of drinking water and protect these water 

resources. Once the SWPP is complete, strategies will be developed for 

protecting the Tribe’s drinking water, planning for the future, and 

contingency planning. (PIIC 2008)

Higgins Eye Mussel Restoration Project

The Tribe has also been collaborating with the Minnesota Department of 

Natural Resources (MNDNR), the U.S. Fish and Wildlife Service (FWS), 

and the U.S. Army Corp. of Engineers (USACE) to restore the Higgins 

eye pearly mussel (Lampsilius higginsii), which has been on the 

endangered species list since 1976. The Higgins pearly mussel aids 

water quality and is a food source for muskrats and otters (an important 

traditional species for tribal members), whose numbers have also 

declined in the last several decades. (PIIC 2008)

The MNDNR, FWS, and USACE are taking mussels from Lake Pepin, 

below Lock and Dam No. 3, where conditions are unfavorable due to the 

zebra mussel, and relocating them to Sturgeon Lake, adjacent to the 

tribe’s land and within Pool 3 of Lock and Dam No. 3, where conditions 

are now more favorable for the mussel. (PIIC 2008)

Habitat Assessment through Breeding Bird Surveys

The tribe conducted an existing habitat assessment by conducting a 

breeding bird survey. In general, excellent habitat will have many species 

of birds, while poor and degraded habitat will have fewer species. The 

field work for this project was completed in June and July 2008 and May 

and June of 2009. In 2008, 72 long-term sampling sites were established 
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in all areas of the reservation. Sixty-nine bird species were surveyed 

during 2008. The same sample sites were visited in 2009 and 75 bird 

species were surveyed. Several species of conservation concern for MN 

were surveyed in both years, including the Bald eagle, Dickcissel, 

Prothonotary Warbler, Cerulean Warbler, Wood Thrush, and the Willow 

Flycatcher. The diversity of habitats on tribal lands—prairies, meadows, 

wetlands, and riparian forests—are important to many of these breeding 

species. The Tribe’s current and future management activities include 

efforts to maintain and enhance existing breeding habitats for birds. (PIIC 

2008)

Invasive Plant Inventory and Native Plant Community Assessment

Because of concerns about invasive plants taking over native plant 

habitat, the Tribe conducted a plant inventory on reservation lands in 

2008. Fortunately, many areas still consist of healthy natural habitats and 

a total of 460 vascular plant species were documented. The project also 

identified 22 invasive plant species on tribal lands. Buckthorn is the most 

prevalent invasive species in Reservation woodland areas; it was 

originally planted as a hedgerow tree and it spread quickly. Purple 

loosestrife was the most prevalent invasive species in wetland areas, 

especially near the Mississippi River. An extensive database and 

vegetation maps were created for this project to assist the Tribe has in 

managing lands in the future. The tribe has also begun the removal of 

buckthorn and purple loosestrife in some areas. (PIIC 2008)

Medicinal and Culturally Important Plants

The Tribe is currently conducting a project to assess the presence of 

medicinal and culturally important plant species on tribal lands. Surveys 

were conducted in the summer of 2008 and are continuing during the 

spring/summer of 2009. As part of the study, the tribe has collected 

voucher specimens for a permanent herbarium. Thus far, 72 of the 180 

potential cultural/medicinal plant species historically present on Prairie 

Island have been found. The medicinal plant survey will help the Tribe 

manage lands and restore areas with plant species that are currently not 

present. (PIIC 2008)

Forest Inventory

The Bureau of Indian Affairs (BIA), Midwest Region, is conducting a forest 

inventory of Tribal lands which will include a delineation of forest cover 

types, such as open prairie, forested wetlands, shrub swamps, and other 

palustrine wetland types. The BIA began the inventory in the fall of 2008

and will complete the project in 2009. The inventory will be beneficial, as 

the data from the inventory will help establish habitat enhancement 

targets. (PIIC 2008)

Draw-down Study of Pool 3 (Sturgeon Lake)

The Prairie Island Indian Community is working with the USACE (St. Paul 

District) on various aspects of a proposed water level management plan 

aimed at modifying river regulation in Pool 3 to improve habitat 

conditions. This ecosystem restoration project would target goals to 
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improve water quality, emergent and submersed aquatic plants, and fish 

and wildlife. (PIIC 2008)

Agricultural Leases

The tribe annually leases 726 ac (290 ha) to tribal members for 

agricultural production. Typically corn and soybeans are planted. (PIIC 

2008)

2.2.8.4 Visual Aesthetics and Noise

PINGP 1 and 2 are located on an island on the west side of the Mississippi River. Both 

units can be seen from the river, but are partly shielded by surrounding vegetation. The 

turbine building and reactor containment structures dominate the landscape of the site.

With mechanical draft cooling towers, the most obvious aesthetic impact is the visible 

steam plume in the sky. The plumes are more persistent under certain meteorological 

conditions when the capacity for the atmosphere to hold additional water vapor is lowest. 

This occurs when relative humidity is high and/or air temperatures are low. Plume rise is 

less with a mechanical-draft tower than it is for a natural-draft tower, and plumes can rise 

to heights between 200 and 500 ft (60 to 150 m) before evaporating completely. (AEC 

1973)

Noise from nuclear plant operations can be detected offsite. Sources of noise from 

PINGP 1 and 2 operations include the mechanical-draft cooling towers, turbines, large 

pumps, and cooling water system motors. Given the industrial nature of the station, 

noise emissions from the station are generally nothing more than an intermittent minor 

nuisance. However, noise levels may sometimes exceed the 55 dBA level that the EPA

uses as a threshold level to protect against excess noise during outdoor activities (EPA 

1974). However, according to the EPA this threshold does “not constitute a standard, 

specification, or regulation,” but was intended to provide a basis for state and local 

governments establishing noise standards.

2.2.8.5 Demography

According to the 2000 Census, approximately 107,131 people lived within 20 mi (32 km)

of PINGP 1 and 2, which equates to a population density of 85 persons per square mile

(mi2

) (NMC 2008). This density translates to the less sparse generic environmental 

impact statement (GEIS) Category 3 (60 to 120 persons/mi2 or less than 60 persons/mi2

with at least one community with 25,000 or more persons within 20 mi [32 km]). 

Approximately 2,733,326 people live within 50 mi (80 km) of PINGP 1 and 2 (NMC 

2008). This equates to a population density of 349 persons/mi2

. Applying the GEIS 

proximity measures, this density is classified as proximity Category 4 (greater than or 

equal to 190 persons/mi2 within 50 mi [80 km]). Therefore, according to the sparseness 

and proximity matrix presented in the GEIS, the rankings of sparseness Category 3 and 

proximity Category 4 result in the conclusion that PINGP 1 and 2 are located in a high 

population area.

Table 2-17 shows population projections and growth rates from 1970 to 2050 in 

Goodhue County and Dakota County, Minnesota, and Pierce County, Wisconsin. The 

growth rate in Goodhue County showed an increase of 8.4 percent for the period of 1990 

to 2000. County populations are expected to continue to grow in all three counties in the 

next decades although Dakota County’s population is expected to increase at a higher 

rate than the others through 2050.
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Table 2-17. Population and Percent Growth in Goodhue County and Dakota 

County, Minnesota, and Pierce County, Wisconsin, from 1970 to 2000 and 

Projected for 2006 to 2050

Year

Goodhue, MN Dakota, MN Pierce, WI

Population

Percent 

Growth(a) Population

Percent 

Growth(a) Population Percent Growth(a)

1970 34,763 — 139,808 — 26,652 —

1980 38,749 11.5 194,279 39.0 31,149 16.9

1990 40,690 5.0 275,227 41.7 32,765 5.1

2000 44,127 8.4 355,904 29.3 36,804 12.3

2007 45,539 3.2 385,971 8.4 39,296 6.8

2010 47,140 6.8 422,990 18.8 39,818 8.2

2020 50,430 7.0 470,460 11.2 42,655 7.1

2030 52,890 4.9 501,020 6.5 45,850 7.5

2040 55,873 5.6 595,611 18.9 49,640 8.3

2050 58,798 5.2 659,939 10.8 52,919 6.6

— = No data available.

(a) Percent growth rate is calculated over the previous decade.

Sources: MSCD 2002; USCB 2008; WDSC 2004

The 2000 and 2006 (estimated) demographic profiles of the three-county region of 

influence (ROI) population are presented in Table 2-18 and Table 2-19. According to the 

2000 Census, minorities (race and ethnicity combined) comprised 8.8 percent of the total 

three-county population. The minority population is composed largely of Hispanic or 

Latino and Asian residents.

Demographic Profile

According to the most recent U.S. Census Bureau’s 2005-2007 American Community 

Survey 3-Year Estimates, minority populations in the three-county region were estimated 

to have increased by nearly 19,700 persons and comprised 12.3 percent of the total 

three-county population (see Table 2-19). The largest increases in minority populations 

were estimated to occur in Black or African American populations. The Hispanic or 

Latino and Asian populations were both estimated to have increased by approximately 

54 percent, and have also increased slightly as a percentage of the total three-county 

population.

Prairie Island Indian Community

Currently, the PIIC has 801 enrolled members; approximately 250 members reside on 

tribal land. The PIIC is growing at an approximate rate of 30 new members per year 

(based on birth rates for the past several years). It is expected that the PIIC will grow by 

600 members over the 20-year PINGP 1 and 2 renewed license period. (PIIC 2009)
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Table 2-18. Demographic Profile of the Population in the PINGP 1 and 2 

Three-County Socioeconomic Region of Influence in 2000

Goodhue, 

MN

Dakota, 

MN

Pierce, 

WI

Region of 

Influence

Total Population 44,127 355,904 36,804 436,835

Race (percent of total population, Not-Hispanic or Latino)

White 96.1 90.0 97.5 91.2

Black or African American 0.6 2.2 0.2 1.9

American Indian and Alaska Native 0.9 0.3 0.3 0.4

Asian 0.6 2.9 0.4 2.4

Native Hawaiian and Other Pacific 

Islander 0.0 0.0 0.0 0.0

Some other race 0.1 0.1 0.1 0.1

Two or more races 0.6 1.5 0.6 1.3

Ethnicity

Hispanic or Latino 473 10,459 301 11,233

Percent of total population 1.1 2.9 0.8 2.6

Minority Populations (including Hispanic or Latino ethnicity)

Total minority population 1,722 35,662 908 38,292

Percent minority 3.9 10.0 2.5 8.8

Source: USCB 2008b
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Table 2-19. Demographic Profile of the Population in the PINGP 1 and 2 

Three-County Socioeconomic Region of Influence in 2005-2007, 3-Year 

Estimate

Goodhue, 

MN

Dakota, 

MN

Pierce,

WI

Region of 

Influence

Total Population 45,539 385,971 36,804 470,806

Race (percent of total population, Not-Hispanic or Latino)

White 95.0 85.9 96.7 87.7

Black or African American 1.0 3.9 0.1 3.3

American Indian and Alaska Native 0.9 0.4 0.4 0.5

Asian 0.8 4.0 1.5 3.5

Native Hawaiian and Other Pacific Islander 0.2 0.0 0.0 0.1

Some other race 0.1 0.2 0.0 0.2

Two or more races 0.4 1.4 0.3 1.2

Ethnicity

Hispanic or Latino 768 16,147 379 17,294

Percent of total population 1.7 4.2 1.0 3.7

Minority Populations (including Hispanic or Latino ethnicity)

Total minority population 2,274 54,392 1,292 57,958

Percent minority 5.0 14.1 3.3 12.3

Source: USCB 2008b

Within 50 mi (80 km) of PINGP 1 and 2, colleges and recreational opportunities attract 

daily and seasonal visitors who create demand for temporary housing and services. In 

2007, approximately 187,000 students attended colleges and universities within 50 mi 

(80 km) of PINGP 1 and 2 (IES 2008).

Transient Population

In 2000, 1.8 percent of all Goodhue County housing units were considered temporary 

housing for seasonal, recreational, or occasional use. By comparison, seasonal housing 

accounted for 0.3 percent and 5.1 percent of total housing units in Dakota County and 

Minnesota, respectively (USCB 2008a). Seasonal housing accounted for 1.3 percent 

and 6.1 percent of total housing units in Pierce County and Wisconsin, respectively 

(USCB 2008). Table 2-20 provides information on seasonal housing for the 25 counties 

located all or partly within 50 mi (80 km) of PINGP 1 and 2.

The Treasure Island Resort and Casino, located on Prairie Island, may have as many as 

16,000 guests at any given time. The hotel also has 480 sleeping rooms (with an 

approximate 90 percent occupancy rate); an RV park (95 pads), and a marina (137 

permanent and daily slips are typically full during the summer months). During the 

PIIC’s annual Pow-Wow in July, an additional 500 to 2000 visitors may be in and around 

the Pow-Wow grounds. The reservation does not have any rental housing units or 

campgrounds. (PIIC 2008).
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Table 2-20. Seasonal Housing in Counties Located within 50 mi (80 km) of 

PINGP 1 and 2

County(a) Housing units

Vacant housing units: For 

seasonal, recreational, or 

occasional use Percent

Minnesota 2,065,946 105,609 5.1

Anoka 108,091 300 0.3

Carver 24,883 124 0.5

Chisago 15,533 679 4.4

Dakota 133,750 381 0.3

Dodge 6,642 18 0.3

Goodhue 17,879 314 1.8

Hennepin 468,824 2,491 0.5

Le Sueur 10,858 973 9.0

Olmsted 49,422 226 0.5

Ramsey 206,448 808 0.4

Rice 20,061 628 3.1

Scott 31,609 150 0.5

Steele 13,306 103 0.8

Wabasha 9,066 239 2.6

Waseca 7,427 79 1.1

Washington 73,635 604 0.8

Winona 19,551 163 0.8

County Subtotal 1,216,985 8,280 1.6 (avg.)

Wisconsin 2,321,144 142,313 6.1

Barron 20,969 2,299 11.0

Buffalo 6,098 247 4.1

Dunn 15,277 285 1.9

Eau Claire 37,474 375 1.0

Pepin 3,036 134 4.4

Pierce 13,493 182 1.3

Polk 21,129 4,211 19.9

St. Croix 24,265 281 1.2

County Subtotal 141,741 8,014 5.6 (avg.)

County Total 1,358,726 16,294 2.9 (avg.)

Source: USCB 2008

(a)Counties within 50 mi (80 km) of PINGP 1 and 2 with at least one block group located within 

the 50-mi (80 km) radius

avg. = percent average for counties within the PINGP 1 and 2 50-mi (80 km) radius and 

excludes state percentage

Migrant farm workers are individuals whose employment requires travel to harvest 

agricultural crops. These workers may or may not have a permanent residence. Some 

migrant workers follow the harvesting of crops, particularly fruit, throughout the rural U.S. 

Migrant Farm Workers
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Others may be permanent residents near PINGP 1 and 2 who travel from farm to farm to 

harvest crops.

Migrant workers may be members of minority or low-income populations. Because they 

travel and can spend a significant amount of time in an area without being actual 

residents, migrant workers may be unavailable for counting by census takers. If 

uncounted, these workers would be “underrepresented” in USCB minority and lowincome population counts.

Information on migrant farm and temporary labor was collected in the 2007 Census of 

Agriculture. Table 2-21 provides information on migrant farm workers and temporary 

farm labor (less than 150 days) within 50 mi (80 km) of PINGP 1 and 2. According to the 

2007 Census of Agriculture, approximately 15,700 farm workers were hired to work for 

less than 150 days and were employed on 4,800 farms within 50 mi (80 km) of PINGP 1 

and 2. The county with the largest number of temporary farm workers (1,025 workers on 

150 farms) was Washington County, Minnesota.

In the 2002 Census of Agriculture, farm operators were asked for the first time whether 

any hired migrant workers, defined as a farm worker whose employment required travel 

that prevented the migrant worker from returning to their permanent place of residence 

the same day. A total of 237 farms in the 50-mi (80-km) radius of PINGP 1 and 2 

reported hiring migrant workers. Dakota County, Minnesota reported the most farms 

(28) with hired migrant workers, followed by Winona County and Goodhue County in 

Minnesota with 22 and 18 farms, respectively.

According to 2007 Census of Agriculture estimates, 970 temporary farm laborers were

employed on 338 farms in Goodhue County and 1,012 temporary farm workers were 

employed on 218 farms in Dakota County (USDA 2007a). Pierce County, Wisconsin, 

had 720 temporary farm workers employed on 298 farms (USDA 2007b).
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Table 2-21. Migrant Farm Worker and Temporary Farm Labor in Counties 

Located within 50 mi (80 km) of PINGP 1 and 2

County(a)

Number of farm 

workers working 

for less than 150 

days

Number of farms 

hiring workers 

for less than 150 

days

Number of farms 

reporting migrant 

farm labor

Number of farms 

with hired farm 

labor

Minnesota 19,337 16,085 54,851 1,186

Anoka 94 77 451 7

Carver 220 177 548 15

Chisago 179 160 612 4

Dakota 270 218 1,012 28

Dodge 207 172 547 9

Goodhue 433 338 970 18

Hennepin 154 110 696 6

Le Sueur 226 194 512 2

Olmsted 300 250 837 11

Ramsey 13 12 66 0

Rice 264 224 671 2

Scott 182 143 496 6

Steele 208 167 552 7

Wabasha 270 207 695 6

Waseca 198 151 532 7

Washington 179 150 1,025 11

Winona 341 255 795 22

Minnesota 

Counties Subtotal

3,738 3,005 11,017 161

Wisconsin 17,889 13,169 45,921 636

Barron 354 251 726 9

Buffalo 274 197 455 11

Dunn 304 219 714 18

Eau Claire 254 193 506 8

Pepin 121 86 196 2

Pierce 358 298 720 7

Polk 277 219 594 4

St. Croix 355 290 793 17

Wisconsin 

Counties Subtotal

2,297 1,753 4,704 76

All Counties Total 6,035 4,758 15,721 237

(a)Counties within 50 mi (80 km) radius of PINGP 1 and 2 with at least one block group

Sources: USDA 2007a; USDA 2007b
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2.2.8.6 Economy

This section contains a discussion of the economy, including employment and income, 

unemployment, and taxes.

Between 2000 and 2007, the civilian labor force in Goodhue County increased 6.6 

percent from 24,100 to 25,692 individuals. During the same time period, the civilian 

labor force in Dakota County and Pierce County grew by 9.6 and 10.3 percent, 

respectively. (USCB 2008a)

Employment and Income

In 2007, educational services, health care and social assistance represented the largest

sector of employment in the three-county region followed by manufacturing and retail 

trade industry. The educational services, health care and social assistance sector 

employed the most people in Goodhue County followed by manufacturing and retail 

trade sectors. A list of some of the major employers in Goodhue County is provided in 

Table 2-22. As shown in the table, the largest employer in Goodhue County is the 

Treasure Island Resort and Casino.

Table 2-22. Major Employers in Goodhue County

Firm or Company Number of Employees

Treasure Island Casino 1500(a)

Red Wing Shoe Co. 724

Xcel Energy 611(a)

Fairview Red Wing Medical Center 585

Independent School District #256 500

Norwood Promotional Products 380

SB Foot Tanning Co. 260

Express Services 236

Cannon Falls Public Schools-ISD#252 230

DB Industries, Inc. 225

Dairy Farmers of America 220

Bergquist Co. 200

Foldcraft-Plymold Co. 200

Gemini Inc. 184

DS Manufacturing Inc. 170

Midwest of Cannon Falls Inc. 164

Cannon Equipment Co. 161

Zumbrota-Mazeppa Public Schools 160

Pine Haven Care Center 150

(a) The ER (NMC 2008) reports the Treasure Island Casino to have 1600 employees and Xcel Energy to 

have 685 employees

Source: MDEED 2009
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Estimated income information for the PINGP 1 and 2 ROI is presented in Table 2-23. 

According to the USCB 2005-2007 American Community Survey 3-Year Estimates

(USCB 2007a), median household income in Dakota and Pierce Counties were each 

above their respective state median household income averages. Conversely, with the 

exception of Dakota County, per capita income in Goodhue County and Pierce County 

were both below their respective state averages. In Goodhue and Dakota Counties, an 

estimated 7.9 and 5.3 percent of the population was living below the official poverty 

level, respectively, while the percentage for the State of Minnesota as a whole was 9.6 

percent. In Pierce County, an estimated 6.9 percent of the population was living below 

the official poverty level, while the percentage for the State of Wisconsin as a whole was 

10.8 percent. The percentage of the population by family living below the poverty level 

was lower in all three counties than their respective state-wide estimates. The 

percentage of families living below the poverty level in Goodhue County (5.7 percent) 

was lower than the percentage of families in the State of Minnesota as a whole (6.3 

percent). Dakota County had a much smaller percentage of families (3.8 percent) living 

below the poverty level. In Pierce County, an estimated 2.3 percent of the families were 

living below the official poverty level, while the percentage for the State of Wisconsin as 

a whole was 7.1 percent. (USCB 2007a)

Table 2-23. 2005-2007 Estimated Income for the PINGP 1 and 2 Region of 

Influence

Goodhue Dakota Minnesota Pierce Wisconsin

Median household income (dollars) 55,098 72,393 55,616 58,011 50,309

Per capita income (dollars) 26,187 33,284 28,536 25,327 25,742

Families living below the poverty 

level (percentage) 5.7 3.8 6.3 2.3 7.1

Individuals living below the poverty 

level (percentage) 7.9 5.3 9.6 6.9 10.8

Source: USCB 2007a

According to the U.S. Census Bureau’s 2005-2007 American Community Survey 3-Year 

Estimates (USCB 2007a), the annual unemployment average in Goodhue and Dakota 

Counties was 5.6 and 5.1 percent, respectively, which were slightly higher and lower 

than the annual unemployment average of 5.4 percent for the State of Minnesota, 

respectively. The annual unemployment average in Pierce County, Wisconsin was 5.4

percent, which was lower than the annual unemployment average of 5.8 percent for the 

state of Wisconsin (USCB 2007a).

Unemployment

In Minnesota, public utilities are valued using cost and income approaches. 

Jurisdictional budgets are developed and taxes are levied to meet those budgets. 

Historically, annual property taxes have been gradually decreasing due to depreciation 

and the growth in Minnesota’s residential and commercial tax bases. Additionally, state 

lawmakers have been conducting hearings for a rule change that could affect the way 

commercial businesses depreciate their facilities. Currently, NSP is unable to fully 

depreciate PINGP 1 and 2. Should the rule change, NSP may be able to increase the 

depreciation on PINGP 1 and 2 to further reduce the plant’s value and tax payments. 

However, NSP plans to implement some refurbishment activities at PINGP 1 and 2 (see 

Taxes
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Chapter 3) that could increase the plant’s assessed value, resulting in an increase in the 

amount of money NSP pays in property taxes.

The Minnesota Department of Revenue (DOR) is in the process of possibly 

revising its current utility company valuation rule. According to a fiscal impact 

study prepared by the DOR and based on the latest draft of the revised rule, the 

amount of property tax revenue received by the city of Red Wing and Goodhue 

County would decrease by approximately $1.4 million and $1.2 million annually, 

respectively. In order to stabilize these communities for their anticipated loss of 

property tax revenue from NSP due to a rule change, NSP executed revenue 

stabilization agreements with Red Wing and Goodhue County representatives in 

November 2006 (City of Red Wing, Minnesota and NSP 2006). NSP is also 

assessed the State General Tax, however, it will not be analyzed here because 

the state’s revenues are very large and NSP’s payments represent an extremely 

small percentage of those revenues. Nuclear fuel is not taxed in the State of 

Minnesota and therefore is not included in the site’s property tax assessment. 

Property taxes are paid directly to Goodhue County, which in turn distributes the 

money to the aforementioned taxing jurisdictions. Property taxes are the chief 

source of revenue for Minnesota counties, generally providing between 30 and 

50 percent of their revenues (AMC 2002).

From 2001 through 2005, Goodhue County collected between $20.6 and $22.3 

million annually in property tax revenues Table 2-24. Goodhue County property 

tax revenues fund, among other things, county operations, public safety, public 

works, cultural and recreational programs, human services, health services, 

roadway maintenance, economic development, and conservation programs 

(Hove 2006). Table 2-24 details the property tax payments made by the owners 

of PINGP for the same years. From 2001 to 2005, PINGP property tax payments 

represented 16.6 to 27.5 percent of Goodhue County’s total property tax 

revenues. 

From 2001 through 2006, the City of Red Wing collected between $8.9 and $11.6 

million annually in property tax revenues Table 2-24. The City of Red Wing’s 

property tax revenues fund city operations. Table 2-24 details the property tax 

payments made by the owners of PINGP for the same years. From 2001 to 

2006, NSP property tax payments represented 52.3 to 36.4 percent of the City of 

Red Wing’s total property tax revenues. Due to small PINGP payment 

decreases and increases in the City’s total revenues collected, NSP’s payment 

percentages are trending downward. 

From 2002 through 2006, the School District 256 collected between $6.5 and 

$6.9 million annually in property tax revenues Table 2-24. From 2002 to 2006, 

PINGP property tax payments represented 28.5 to 38.0 percent of the School 

District 256’s total property tax revenues. Prior to 2002, PINGP tax payments to 

School District 256 were significantly larger because the state-determined local 

school tax was included in School District 256 payments prior to year 2002. The 

2001 Tax Law provided for major changes in the source of school funding in 

Minnesota and replaced the state-determined local school tax with the State 

General Tax, a statewide property tax levied for taxes payable on commercial, 

industrial and seasonal properties. Taxes under the State General Tax are paid 

into the State General Fund and redistributed by a state-determined formula to 

school districts state-wide, in part, based on student numbers. The State 
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General Tax is levied at a uniform rate within each county, and the levy rate is 

determined by the Commissioner of Revenue (Fredrikson & Byron 2001).

Table 2-24. PINGP 1 and 2 Property Tax Paid and Percentage of Goodhue 

County, City of Red Wing, and School District 256 Tax 

Revenues, 2001 to 2006

Entity Year

Total Revenue

(millions of dollars) 

Property Tax

Paid by NSP

(millions of dollars)

Percent of 

Total Revenue 

Goodhue County 2001 21.0 5.8 27.6

2002 20.6 4.6 22.3

2003 21.1 4.4 20.9

2004 21.7 4.0 18.4

2005 22.3 3.7 16.6

2006 22.4 3.7 16.5

City of Red Wing 2001 8.9 4.7 52.8

2002 10.9 4.8 44.0

2003 11.4 4.8 42.1

2004 11.5 4.5 39.1

2005 10.9 4.0 36.7

2006 11.6 4.3 37.1

School District 256 2001 14.8 6.6 44.6

2002 6.5 2.5 38.5

2003 5.7 2.0 35.1

2004 6.9 2.1 30.4

2005 6.7 1.8 26.9

2006 6.9 2.0 29.0

Source: NMC 2008; OSA 2007

In 2003, the PIIC entered into a Settlement Agreement with NSP, which includes certain 

provisions that relate to the PIIC’s long-standing health and safety concerns about 

PINGP 1 and 2. (Minn. Stat. § 216B.1645, Subd. 4; Laws 2003, First Special Session 

Chapter 11.) This agreement was approved by the Minnesota Public Utilities 

Commission (MN PUC) and the Minnesota Legislative. Through the Agreement, funds 

are allocated to the PIIC to address a variety of issues: health concerns, emergency 

management, land acquisition, construction of community infrastructure, or other 

community purposes. The Agreement is in place as long as PINGP 1 and 2 are 

operational and the ISFSI continues to be used for dry cask storage, although certain 

provisions of the Agreement end when the current operating licenses expire. (PIIC 

2008). 

NSP also provided $25,000 to the PIIC to fund a preliminary engineering study or other 

activities to help facilitate the construction of an overpass over the railroad lines which 

cross Sturgeon Lake Road, which is the only exit from the reservation (PIIC 2008). 

Similar to the support it provides to Goodhue County and the State of Minnesota, NSP 

also provides the PIIC with up to $17,000 annually to reimburse the Community for 
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radiological emergency preparedness (REP) activities, such as training, travel to 

meetings, and supplies (PIIC 2008; 2009).

2.2.9 Historic and Archaeological Resources

This section discusses the cultural background and the known historic and 

archaeological resources at the site of PINGP 1 and 2 and in the surrounding area.

2.2.9.1 Cultural Background

The region around PINGP 1 and 2 contains prehistoric and historic Native American and 

Euro-American cultural resources. Sixty properties in Goodhue County are listed in the 

National Register of Historic Places (NRHP) (NPS 2009). Of these, 35 properties are 

located in Red Wing within 6 mi (9.7 km) of PINGP 1 and 2. The nearest property, the 

Bartron Village site, is partially located on the PINGP 1 and 2 site. Nine properties are 

located across the Mississippi River in Pierce County, Wisconsin. Two of these 

properties are within 6 mi (9.7 km) of PINGP 1 and 2.

The land around Prairie Island is composed of limestone cliffs and various river 

drainages, and is bounded by the Cannon and Trimbelle River Bluffs (Dobbs 1988; 

Schirmer 2002). Prairie Island was formed from the deposition of enriched silt resulting 

from glacial melt and periodic flooding from the Mississippi and other river drainages 

(Gibbon 1979). The USACE Lock and Dam No. 3, constructed in the 1930s, created 

Sturgeon Lake and flooded portions of the island, obscuring the original shoreline. The 

landscape within the PINGP 1 and 2 site boundary is mostly level with some wooded 

and swampy areas. The majority of the land is now underbrush and woods. 

Paleo-Indians migrated into Southern Minnesota approximately 10,000 to 12,000 years 

ago when the glaciers receded and the forests and prairies reappeared (Scullin 1996). 

Paleo-Indian populations were highly mobile and left little evidence of their activities. 

Most Paleo-Indian sites would have been short-term occupations (campsites). PaleoIndian people subsisted on hunted game and gathered plant material. The early PaleoIndian period dates from 9550 B.C. to 8050 B.C. and includes the Clovis and Folsom 

cultures (Dobbs 1988). The primary artifact associated with the Paleo-Indian period is 

the Clovis point: a distinctive, fluted, lanceolate point. To date, no intact Clovis or 

Folsom sites have been identified within Minnesota; however spear points have been 

found. The late Paleo-Indian period dates from 8050 B.C. to 6050 B.C. 

Prehistoric Periods

During the Archaic Period, from approximately 6050 B.C. to 1050 B.C., subsistence 

hunting and gathering underwent changes to adapt to resource availability. As glaciers 

retreated northward and larger animals disappeared from the region, humans adapted to 

modern plants and smaller game animals. Very few intact Archaic period sites have 

been found in Minnesota. Most information comes from surface finds and private artifact 

collections. Rapid climate changes and subsequent flooding may have buried or 

disturbed many Archaic sites. Archaic people did not appear to establish permanent 

settlements, though there is evidence that some areas were utilized frequently. Archaic 

people collected, hunted, and gathered most of what they needed for survival in their 

home territory. There are no known Archaic sites within Goodhue County (Dobbs 1988).

The Woodland culture existed from 1050 B.C. until European contact around 1600 A.D. 

This period is defined by the introduction of horticulture to augment subsistence hunting 

and gathering. A reliance on agriculture led to the establishment of more permanent 

settlements during this period. In Minnesota, Woodland culture is also defined by the 
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production of pottery and earthen mound construction, though there is evidence that 

suggests that these technologies were present in earlier periods. Other characteristics 

of Woodland culture include increased population, emergence of social hierarchy, 

expanded interregional trade, and the introduction of the bow and arrow. Woodland 

peoples exchanged ideas and technologies with other locations in the Midwest. This 

period is typically divided into Early, Middle, and Late Woodland periods (Dobbs 1988). 

Changes in climate during this period caused changes in Woodland culture.

Very few Early Woodland cultural sites have been found in Minnesota and most are 

located in the southeastern portion of the state where the deciduous forest dominates 

the landscape. Early Woodland settlements were small and seasonally occupied. Sites 

from this period are difficult to locate and may be deeply buried.

In contrast, the Middle Woodland period is defined by more elaborate ritual and mortuary 

activities and increased trade. Mounds built during this time are larger than those found 

later in the earlier Woodland period and include linear mounds, log crypts, and multiple 

burials (Dobbs 1988). Communities that lived in and around the Ohio and Mississippi 

valleys, including Prairie Island, acquired a wide range of exotic goods and raw materials 

from all over North America. Middle Woodland communities were linked by a network 

archaeologists refer to as the Hopewell Interaction Sphere involving the dissemination of 

ideas about social organization, technology, and long distance trade from various 

centers of Hopewell culture.

Late Woodland cultures are poorly understood in Minnesota. Many Late Woodland sites 

are located on floodplains where site preservation is compromised by flooding and 

erosion. Additionally, pottery types found in the area have not been well defined in 

Minnesota. Population densities in the Late Woodland were low and the peoples lived 

as hunters and gatherers (Dobbs 1988). Typical sites include mound groups (conical or 

effigy mounds ranging from two to fifteen mounds), short-term seasonal occupations, 

seasonal villages, rock shelters and caves, and shell middens (archeological feature 

comprised mainly of mollusk shells).

Two major cultural phases that follow or concurrently existed with the Late Woodland 

period are the Silvernale and Oneota cultures. Current research is unable to clearly 

define the level of interactions between the Late Woodland, Oneota, and Mississippianrelated cultures in Minnesota. The period of most concentrated use of the Red Wing 

area, which includes Prairie Island, was the Silvernale Phase that is associated with the 

Mississippian culture (A.D. 1000 to 1300). The Silvernale Phase is distinguished by the 

presence of local and non-local pottery styles and decorations. Silvernale Phase 

artifacts are only found in the Red Wing area, unlike the Oneota artifact assemblages 

which are found throughout the Midwest (Gibbon and Dobbs 1991). There are at least 

seven major village sites in the Red Wing area.

One example is the Bartron Village site (21GD02). The Bartron Village site has yielded 

Oneota and Late Woodland components, and some Mississippian-related artifacts. This 

multi-component site (from A.D. 1050 to 1300) is important for understanding the cultural 

evolutionary and settlement patterns at Prairie Island. Oneota peoples are among some 

of the ancestors to the Chiwere, and Dakota and Dheigiha Sioux-speaking peoples 

(Schirmer and Hildebrandt 2008).

Oneota and Silvernale villages typically have associated mound groups. These mound 

groups are numerous and are usually conical and/or linear (ellipsoid) shaped. Oneota 

and Mississippian-related habitation sites include semi-permanent (seasonal) Oneota or 

Silvernale villages, (possibly fortified) permanent Silvernale villages, outlying Silvernale-
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related farmsteads, garden plots, quarry sites, and sites associated with elite 

architecture and trade activities (Dobbs 1988).

During both prehistoric and historic (European contact) periods, the Mississippi River 

and its tributaries played an important role in the settlement and history of the region. 

The Mississippi River was the major means of transportation of people and goods 

resulting in a high density of prehistoric and historic sites along the Red Wing and Prairie 

Island areas (NMC 2008). There are hundreds of habitation sites in Goodhue and 

Pierce Counties, however, very few sites have been tested or professionally excavated.

During the 17th century, the two major tribes within Minnesota were the Dakota (Sioux) 

and the Ojibwe (Chippewa) (Willis 1914). Father Louis Hennepin was the first European 

to explore the Upper Mississippi River region. In 1680, he was captured near Milles 

Lacs by a Dakota war party and later recorded Lake Pepin and St. Anthony Falls while in 

captivity (Willis 1910). 

Historic Period

In 1685, another Frenchman Nicholas Perrot established a trading post at Trempealau 

on the east bank of the Mississippi River, and Fort Saint-Antoine on Lake Pepin 

(Kneisler 1999). Frenchman, Pierre Charles Le Seuer, explored the region at the 

confluence of the Mississippi and Minnesota rivers, where Fort Snelling was later 

established. Le Seuer built a trading post on Prairie Island around 1695 (AEC 1973).

Evidence indicates that Le Sueur wintered on the southern end of Prairie Island from 

1694 to 1695; however, this encampment has never been found (Hildebrandt 2008,

Hildebrandt Iffert 2010). Historic Dakota encampments and trading posts were also 

reported to exist on Prairie Island though none have been found (Hildebrandt 2008). 

Around 1727, the French built Fort Beauharnois on the Mississippi River which facilitated 

the trade of furs with the Dakota people (MNDNR 2008). A chapel built at Fort 

Beauharnois, named the Mission of St. Michael the Archangel, is purported to be the first 

Christian church in Minnesota. In 1763, the Treaty of Paris ended the French and Indian 

War (MNDNR 2008). As a result, Fort Beauharnois and the Frontenac settlement were 

abandoned. Subsequently, most of France’s land holdings within the New World were 

divided between Spain and England.

Fort Snelling was built between 1819 and 1825 by the U.S. Army (MNHS 2009). Fort 

Snelling was an important outpost that provided a meeting place for the U.S. 

government officials and representatives of the Dakota and Ojibwa nations. The 

American and Columbia fur companies also constructed headquarters in this area, and 

the families of these employees settled at nearby Mendota. European immigrants and 

settlers from the East Coast established a settlement that later became St. Paul City 

(MHS 2009). Europeans settled on the west bank of the Mississippi River as a result of 

a treaty signed at Mendota in 1851. In 1857, Red Wing was incorporated as a city. A 

year later, in 1858, the territory of Minnesota became the 32nd state (City of Red Wing 

2003).

According to a tribal elder (born in 1937), the land now owned by Xcel/NSP was 

predominately owned by two families. The Nauer family owned most of the land where 

PINGP 1 and 2 are located. Two Nauer family members are still residing (and farming) 

in the vicinity. The Larson family owned most of the land that is closest to the tribe’s 

land (Edoka Street vicinity), where the north-south transmission lines are located. These 

two families had homesteads and barns. Whether these are the 5 cottages referenced 

in the 1973 AEC FES is unknown. (PIIC 2008)
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Today’s PIIC members are descendents of the Mdewakanton Band of Eastern 

Dakota, who are also known as the Mississippi or Minnesota Sioux, who were 

parties to treaties with the U.S. Government from 1805 to 1863. Members of the 

PIIC have lived on Prairie Island for countless generations. According to 

archaeological evidence, Prairie Island has been a place of historical and cultural 

significance for thousands of years. The descendants of those earliest known 

inhabitants, the Mdewakanton Dakota (Sioux), traditionally used Prairie Island as 

a summer encampment for fishing, hunting, gathering medicines and foods, and 

raising crops.

History of the Prairie Island Indian Community

The Prairie Island people are also part of a larger group called the “Dwellers of 

the Spirit Lake,” or in the Dakota language, the Mde wakan ed otunwahe. This 

name has been shortened over the years to Mdewakantonwan or Mdewakanton 

(M’DAY-wah-kahn-tahn). The Mdewakanton are one of the seven sub-tribes who 

make up the alliance known as Oceti Sakowin - the Seven Council Fires. This 

alliance is more commonly known as the Sioux, which comes from an Ojibwe 

word nadowessi for “Little snakes.” The name was changed by the French to 

Nadowesioiux or simply Sioux. Today, the Sioux call themselves Dakota, 

Lakota, or Nakota, a word that means “allies” or “friends” in all three dialects. 

The Dakota, Lakota, and Nakota have reservations in the states of Minnesota, 

Nebraska, South Dakota, North Dakota, and Montana, and in the Canadian 

provinces of Manitoba and Saskatchewan.

The following four paragraphs are provided by the PIIC as a history of the Dakota 

Uprising and PIIC land acquisition.

In 1891, the U.S. Secretary of the Interior purchased 120 ac (49 ha) of 

land on Prairie Island for the benefit of the Mdewakanton Sioux in 

Minnesota who did not participate in the Dakota Uprising of 1862, an 

armed conflict between the United States and several bands of the 

Eastern Dakota which began on August 17, 1862, along the Minnesota 

River in southwest Minnesota.

During the early to mid-1800s, the Dakota ceded vast tracts of land to the 

U.S. Government through various treaties with the U.S. In exchange, the 

Dakota were promised cash and annuities (goods and food) by the U.S. 

Government. Very little of the appropriated cash and annuities was 

actually paid to the Dakota, but instead went directly to the traders from 

whom the Dakota were purchasing goods. Tensions rose during the 

summer of 1862 when crops failed, the annuity payments were delayed, 

the U.S. Government refused to hand out food that was stored for the 

Dakota, and the traders refused to allow the Dakota to purchase food and 

goods on credit. The resulting severe food shortages caused widespread 

hunger among the Dakota.

Frustrated with this situation and the continued encroachment of their 

lands, a council of Dakota decided to attack settlements throughout the 

Minnesota River Valley in an effort to drive whites out of the area. 

Continued battles between the Dakota against settlers and later, the U.S. 

Army, culminated with the surrender of most of the Dakota. On 

September 26, 1862, over 1200 Dakota men, women, and children were 

taken into custody at Fort Snelling, Minnesota. Two days later, on 
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September 28, 393 Dakota were tried for their involvement in the conflict; 

303 were sentenced to hang. On December 26, 1862, 38 Dakota were 

hanged in Mankato, Minnesota; this was the largest mass execution in 

U.S. history. In April of 1863, the rest of the Dakota were expelled from 

Minnesota and the U.S. Congress abolished their reservations.

This land purchased in 1891 for the Mdewakanton Sioux at Prairie Island 

was assigned to individual Mdewakanton Sioux members (in 5 and 10 ac 

[2 and 4 ha] tracts) residing on Prairie Island. These land assignments, 

also known as the Red Seal Lands, were originally restricted to the 

descendents of the Mdewakanton Sioux who were residing in the State of 

Minnesota on May 20, 1886. A 1980 Act of Congress changed the status 

of those lands, transferring them into trust for the benefit of the PIIC.

Following the Indian Reorganization Act of 1934, the U.S. Government 

purchased and placed into trust an additional 414 ac (168 ha) of land for the 

PIIC. This purchase, which abutted the original 120 ac (49 ha), established the 

Prairie Island Reservation. Over the last several years, the PIIC has been able 

to expand its land base through the purchase of additional adjacent lands. The 

“Prairie Island Land Conveyance Act of 2005,” passed by Congress in 2005, 

authorized the transfer of an additional 1,300 ac (526 ha) of USACE land (485 ac

[196 ha] of forested wetlands and prairie and 819 ac [819 ha] of open water) to 

the PIIC. Today, the PIIC has grown to over 3,000 ac (1200 ha) (including land 

and water). Additionally, the tribe owns 685 ac (277 ha) of land (in Goodhue 

County) that are not in Trust and not considered part of the reservation, 465 ac 

(188 ha) in Florence Township and 259 ac (105 ha) in Welch Township.

2.2.9.2 Historic and Archaeological Resources

There are 13 archaeological sites on the PINGP 1 and 2 property including 11 recorded 

archaeological sites and 2 reported, but unrecorded, sites (Vergil Larson II Mound Group 

site [21GDI] and the Prairie Island District 132 Schoolhouse) (see Table 2-25). The 

earliest investigation on Prairie Island was conducted by T.H. Lewis in 1885. Lewis was 

a surveyor for the Northwest Archaeological Survey. He documented the presence of 

hundreds of mounds and created a series of maps. Lewis never published his notes or 

maps. Lewis’s work was followed by Jacob Brower and Warren Upham in the late 

1880s. Many of the sites documented by Lewis were recorded in relation to a shoreline 

that no longer exists due to flooding from the construction of dams on the Mississippi 

River (Hildebrandt 2008, Hildebrandt Iffert 2010). The discussion below is a 

chronological summary of the archaeological surveys and studies performed in the 

vicinity of the PINGP 1 and 2 site.

Previous Archaeological Research at Prairie Island

In the 1940s and 1950s, Lloyd Wilford, a professor at the University of Minnesota, 

continued the archaeological study of mounds and other sites on Prairie Island. He 

conducted a number of interviews with landowners and excavated some mounds and 

archaeological sites on the island. He also conducted archaeological investigations at 

the Bartron Village site (21GD02).

In the 1960s, Elden Johnson conducted several archaeological surveys and salvage 

excavations on Prairie Island. During a 1960 survey, Johnson reportedly located 41 

burial mounds, at least 7 and possibly 10 mounds may have been located on PINGP 

property. In 1967, in anticipation of the construction of PINGP 1 and 2, Johnson 
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conducted and coordinated surveys and excavations with NSP and the Minnesota 

Historical Society (MHS). Johnson identified and recorded an Oneota village (21GD02, 

previously excavated by Wilford in 1948) ,and in 1980, site 21GD148, a prehistoric 

habitation site. Archaeological excavation of 21GD02 uncovered various subsurface 

features, including storage/refuse pits, fire hearths, and postmolds. Portions of two 

houses were also uncovered.
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Table 2-25. Archaeological Sites within the PINGP 1 and 2 Site Boundary

Condition*

Site 

Number Site Name Description NRHP Status State Site File** Merjent Report 

21GD02 Bartron Site Artifact 

Scatter –

Base Camp

Listed 1970 On Xcel property –

70% moderate due to 

agricultural activity; 

20% heavily disturbed 

due to historic and 

modern use; 10% 

completely destroyed 

due to archaeological 

excavation, borrow pit, 

and road construction

Moderately disturbed 

by cultivation, road 

construction, and 

archaeological 

investigation.

Distu

prope

mode

(culti

distu

mode

comp

(arch

borro

cons

21GD58/

61

Birch Lake 

Mound 

Group

Earthwork, 

CemeteryMortuary 

(Eight 

mounds)

Undetermined 90% heavily disturbed 

due to archaeological 

excavation

Heavily disturbed 

byarchaeological 

excavation

Heav

(railro

cultiv

exca

21GD59 NSP II 

Mound 

Group

Earthwork 

(Six mounds); 

Mississippian 

affiliation

Undetermined 1981 last update 

disturbed/destroyed

Heavily disturbed by 

construction, possibly 

capped by spoil 

deposits. Small area 

of the site may be 

undisturbed.

Heav

(culti

of co

areas 

spoil 

21GD62 Birch Lake 

Mound

Earthwork 

(One mound); 

probable 

Woodland 

affiliation

Undetermined Completely destroyed 

by archaeological 

excavation

Heavily disturbed by 

mechanical trenching 

during archaeological 

excavation

Com

(arch
2-75

Condition*

Site 

Number Site Name Description NRHP Status State Site File** Merjent Report 

21GD148 Cooling 

Tower Site

Artifact 

Scatter, 

Woodland and 

probable 

Mississippian 

affiliation

Undetermined, 

nominated by E. 

Johnson in 

1980; not listed

Unassessed condition

(no known threats) 

Not sufficient evidence 

to assess; one flake 

observed in 2009

Unas

(unas

21GD149 Substation 

Site

Artifact 

scatter, 

possible 

Woodland and 

probably 

Oneota 

affiliation

Undetermined Unassessed condition 

(erosion)

No evidence in 2009; 

possible mound 

discredited in 2009

Unas

(eros

21GD207 Dike Site Artifact 

scatter. 

Woodland 

affiliation

Undetermined Unknown (no evidence 

of site in 2009)

No evidence in 2009 Unkn

site in 

21GD277 Indian 

Slough 

Mound

Earthwork Undetermined Minimally disturbed

(no known threats)

Relatively undisturbed Minim

21GD278 Otto Phlika 

Farmstead

Farm Undetermined Moderately disturbed

(no known threats)

Poor surface 

condition; subsurface 

deposits unknown

Mode

21GD279 Kuhns 

Farmstead

Farm Undetermined Moderately disturbed 

(development)

Poor surface 

condition; subsurface 

deposits unknown

Mode

(deve
Affected Environment

2-76

Condition*

Site 

Number Site Name Description NRHP Status State Site File** Merjent Report 

21GD280 Reliance 

Stove Door 

Site

Artifact 

scatter, 

possible 

homestead

Undetermined Unassessed

(erosion)

Subsurface deposits 

unknown

Unas

21GDl Vergil Larson 

Mounds II

Earthwork 

(Reported 3 

mounds)

Unevaluated Not field verified No mound observed in 

portion of site within 

PINGP boundary

Not f

No site 

number

Prairie Island 

District 132 

Schoolhouse 

Site

Subsurface 

remains of 

District 

Schoolhouse 

(1873 to 

1953)

Unevaluated No form Unas

Source: Boden 2008; Hildebrandt 2008, Hildebrandt Iffert 2010; Boden et. al 2010

*Condition is assessed under “Degree of Disturbance” on Minnesota Archaeological site forms as minimal, moderate, heav

unassessed/unknown. Labels of site condition per the Office of the State Archaeologist. 

**Condition assessments on the OSA site forms are based upon the archaeologist performing the assessment; this does n

of the State Archaeologist. 
Affected Environment

2-77

In 1968, the U.S. Atomic Energy Commission (AEC) issued the construction permits for PINGP 

1 and 2. Shortly after the issuance of the permits, archaeological excavations began at the 

Bartron Village Site (21GD02), and continued through 1969. In 1979, Guy Gibbon documented 

the results from Johnson’s 1968 and 1969 excavations at the Bartron Village Site (21GD02). 

Johnson also coordinated excavations at the Birch Lake Mound Group (21GD58/61) and the 

NSP II Mound Group (21GD59). Excavations at the Birch Lake Mound Group (21GD58/61) 

yielded enough information for publication (Johnson, Peterson, and Streiff 1969). There is no 

summary of the excavations conducted at the NSP II Mound Group (21GD59).

The layout of the PINGP 1 and 2 cooling towers was modified several times, finally resulting in 

an east-west configuration. Burial mounds at the NSP II Mound Group (21GD59) were reported 

to be in the vicinity and artifacts were encountered during excavation and were curated at the 

Minnesota Historic Society (MNHS) (Hildebrandt 2008, Hildebrandt Iffert 2010). The four 

remaining mounds were either covered with fill or leveled during grading activities for the PINGP 

1 and 2 cooling towers. No human remains were encountered.

In 1970, the Bartron Village Site (21GD02) was listed on the National Register of Historic Places 

(NRHP). NSP agreed to set aside the southern portion of the PINGP 1 and 2 property for 

archaeological preservation (NMC 2008).

A voluntary ban on excavating Indian burials in Minnesota began in the mid-1970s. Minnesota's 

Private Cemeteries Act (M.S 307.08) protects “...all human burials, human remains, and human 

burial grounds shall be accorded equal treatment and respect for human dignity without 

reference to their ethnic origins, cultural backgrounds, or religious affiliations. The provisions of 

this section shall apply to all human burials, human remains, or human burial grounds found on 

or in all public or private lands or waters in Minnesota.” Previously, burials on public land were 

protected while burials on private land were not afforded the same protection. 

In the early 1980s, Christine Harrison of the MNHS conducted a systematic survey of Goodhue 

County, including the PINGP 1 and 2 site. At this time, Elden Johnson returned to PINGP 1 and 

2 to conduct archaeological investigations for the modification of the cooling discharge canal. 

Sites potentially impacted by the proposed modification were the NSP II Mound Group 

(21GD59) and the 21GD148 habitation site (Hildebrandt 2008, Hildebrandt Iffert 2010). A new 

site, 21GD207, an artifact scatter, was also identified during this survey. Johnson completed his 

final report in December 1980. Site 21GD148 was nominated to the NRHP though it did not 

make the list. Also in 1980, but unrelated to the canal survey work, another new site (21GD149) 

was discovered eroding out of a river bank by NSP biologists on land owned by the USACE and 

leased by NSP. In 1991 and 1994, archaeological surveys and testing continued on the PINGP 

1 and 2 property, with no artifacts recovered and no cultural findings.

In 1999, the PIIC hired The 106 Group, Ltd., to perform an archaeological reconnaissance 

survey and Geographic Information Systems (GIS) inventory of archaeological sites on and in 

the vicinity of the PIIC. Survey efforts during the inventory were unable to field verify the Vergil 

Larson II Mound Group (21GDI). No subsurface testing was attempted in the area out of 

respect for the potential burials interred in the mounds (Abel et al. 1999).

Xcel Energy (Xcel) contracted with The 106 Group, Ltd., in 2008 to conduct a cultural resources 

assessment of archaeological sites located on and in the immediate vicinity (within 1 mi [0.6 

km]) of the PINGP 1 and 2 site (Boden 2008). Xcel also partnered with Minnesota State 

University, Mankato, to conduct archaeological excavations of the Bartron Village Site 

(Hildebrandt 2008, Hildebrandt Iffert 2010).

In late 2008, Xcel contracted Merjent, Inc. to conduct a Phase I survey in the area of the dredge 

holding pond expansion. This survey found no cultural material but concern about the 
Affected Environment

2-78

possibility for deeply buried sites led to additional testing (Boden 2009). In 2009, deep core 

samples were collected to look for deeply buried archaeological sites, but none were found 

(Hudak 2009).

During the summer of 2009, Merjent, Inc. conducted a limited Phase I pedestrian survey 

(without subsurface testing) within the PINGP property. The survey re-located eight recorded 

archaeological sites (21GD02, 21GD58/61, 21GD59, 21GD62, 21GD148, 21GD149, 21GD207, 

and 21GDl) (Boden, et. al. 2010). The survey also identified five new sites on the PINGP 

property (21GD277, 21GD278, 21GD279, 21GD280, and the Prairie Island Schoolhouse). This 

survey also noted the existence of a mound with intrusive European American graves (Nauer 

Cemetery) located on private property, south of the PINGP fenceline (Boden et. al 2010).

Traditional cultural properties are cultural resources that are historically important for a 

community to maintain its cultural heritage. Examples of traditional cultural properties include 

gathering areas, plant material, a sacred mountain and/or landscape that is crucial to a 

community’s identity, or burial locations that, for example, connect American Indians with their 

ancestors. Most traditional cultural properties can be identified only through consultation with 

members of these communities. Identifying traditional cultural properties is an important part of 

the Section 106 consultation under the National Historic Preservation Act (NHPA). 

Traditional Cultural Properties

While no traditional cultural properties have been identified at the PINGP 1 and 2 site, there is 

the potential for these properties to exist. The PIIC has also expressed concern about invasive 

plants on Prairie Island displacing native species that are culturally significant to the PIIC. Many 

of these plants are used as medicines and in religious ceremonies by members of the PIIC. A 

2008 survey conducted by the PIIC found 22 invasive plant species on tribal lands. Work is 

underway to remove buckthorn and purple loosestrife from some areas (PIIC 2009).

Because of concerns about declining native plant species, the PIIC conducted an 

inventory of medicinal and culturally important plant species on tribal lands. The 

inventory, which was conducted in the fall of 2008 and spring/summer of 2009, is a 

follow-up to an inventory conducted in 1998 (PIIC 2009). According to the 1998 

inventory, 70 percent of the original native medicinal and culturally significant plant 

species have been lost during the last generation. Of the 189 medicinal or culturally 

important plant species historically present on Prairie Island and used by tribal members, 

only 52 were identified in the 1998 field survey. The 1998 study also discussed the 

findings of past plant studies conducted by NSP within the boundaries of PINGP 1 and 2 

since 1975. Medicinal and culturally important plant species found to be present in both 

the Xcel/NSP and Prairie Island studies included: yarrow, ragweed, big milkweed, lamb’s 

quarter, wild strawberry, sunflower, sweet clover, sand primrose, Virginia creeper, 

goldenrod, and pennyroyal. (PIIC 2009)

As part of the 2008/2009 inventory, Tribal elders were interviewed to gain a historical 

perspective on the locations and uses of these plants on the PIIC Reservation. Some elders 

stated that medicinal plants they have used in the past were not as strong or abundant as they 

once were. All of the elders interviewed agreed that conducting periodic surveys is important 

and that the PIIC should develop some kind of management plan to protect species, enhance 

growing conditions, and educate PIIC members about native plant species and their uses. (PIIC 

2009)
Affected Environment

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2.3 Related Federal and State Activities

The NRC staff reviewed the possibility that activities of other Federal agencies might impact the 

renewal of the operating license for PINGP 1 and 2. Any such activity could result in cumulative 

environmental impacts and the possible need for a Federal agency to become a cooperating 

agency in the preparation of the PINGP 1 and 2 SEIS.

The NRC staff has determined that there are no Federal projects that would make it desirable 

for another Federal agency to become a cooperating agency in the preparation of the SEIS. 

Federal facilities and National Parks within 50 mi (80 km) of PINGP 1 and 2 are listed below. 

• St. Anthony Falls Lock and Dam

• Lower St. Anthony Falls Lock and Dam

• Lock and Dam 1

• Lock and Dam 2

• Lock and Dam 3

• Mississippi National River and Recreation Area

• Fort McCoy (U.S. Military Installation)

• Army National Guard Family Assistance Center

• Minneapolis-St. Paul Air Reserve Station

The NRC has entered into a Memorandum of Understanding (MOU) with the PIIC for the PINGP

1 and 2, license renewal application review, which is described in more detail in Section 1.6. 

The American Indian lands listed below lie within 50 mi (80 km) of PINGP 1 and 2. Tribal 

agencies contacted during the environmental review in addition to those listed below are listed 

in Section 1.8 of this SEIS.

• Prairie Island Indian Community, Welch, Minnesota

• Shakopee Mdewakanton Sioux Community, Prior Lake, Minnesota

NRC is required under Section 102(2)(c) of the National Environmental Policy Act of 1969 

(NEPA) to consult with and obtain the comments of any Federal agency that has jurisdiction by 

law or special expertise with respect to any environmental impact involved. NRC has consulted 

with the American Council on Historic Preservation and the FWS. Federal Agency consultation 

correspondence and comments on the SEIS are presented in Appendix D.

2.4 References

10 CFR 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for Protection 

Against Radiation.”

10 CFR 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic Licensing of 

Production and Utilization Facilities.”

10 CFR 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental Protection 

Regulations for Domestic Licensing and Related Regulatory Functions.”

10 CFR 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for Renewal 

of Operating Licenses for Nuclear Power Plants.”
Affected Environment

2-80

10 CFR 61. Code of Federal Regulations, Title 10, Energy, Part 61, “Licensing Requirements

for Land Disposal of Radioactive Waste.”

10 CFR 71. Code of Federal Regulations, Title 10, Energy, Part 71, “Packaging and 

Transportation of Radioactive Material.”

10 CFR 100. Code of Federal Regulations, Title 10, Energy, Part 100, “Reactor Site Criteria.”

40 CFR 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

“Designation of Areas for Air Quality Planning Purposes.”

40 CFR 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

“Environmental Radiation Protection Standards for Nuclear Power Operations.”

40 CFR 239, et seq. Code of Federal Regulations, Title 40, Protection of Environment, Chapter 

I, Environmental Protection Agency, Subchapter I, “Solid Wastes.”

40 CFR 261. Code of Federal Regulations, Title 40, Protection of Environment, Part 261, 

“Identification and Listing of Hazardous Waste.”

40 CFR 262. Code of Federal Regulations. Title 40, Protection of Environment, Part 262, 

“Standards Applicable to Generators of Hazardous Waste.”

40 CFR 266. Code of Federal Regulations, Title 40, Protection of Environment, Part 266, 

“Storage, Treatment, Transportation, and Disposal of Mixed-Waste.”

40 CFR 273. Code of Federal Regulations, Title 40, Protection of Environment, Part 273, 

“Standards for Universal Waste Management.”

41 FR 24064. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

endangered status for taxa of animals. June 14, 1976.

63 FR 31268. U.S. Environmental Protection Agency. Changes to the hazardous chemical 

reporting regulations. June 8, 1998.

72 FR 37346, U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

removing the Bald Eagle in the lower 48 states from the list of endangered and threatened 

wildlife. July 9, 2007.

73 FR 65452, Environmental Protection Agency. “Emergency Planning and Community Rightto-Know Act; Amendments to Emergency Planning and Notification; Emergency Release 

Notification and Hazardous Chemical Reporting; Final Rule.” Federal Register: Volume 73, No. 

213, pp. 65452-65484.

Abel, Elizabeth, Zakariah Johnson, and Mollie M. Lyon. 1999. Phase 1 Archaeological 

Reconnaissance Survey and GIS Inventory for the Prairie Island Indian Community, Prairie 

Island Reservation and Parcel D, Goodhue County, Minnesota. Final Report. Submitted to the 

Prairie Island Indian Community and St. Paul District Corps of Engineers. St. Paul, MN. The 

106 Group Ltd. August. Non-public reference per 36 CFR 800.11(c), NHPA § 304[16 U.S.C. 

470w-3(a) — Confidentiality of the location of sensitive historic resources], and Minnesota

Statute 307.08, Sub. 11.

AEC (Atomic Energy Commission). 1973. Final Environmental Statement Related to the 

Operation of Prairie Island Nuclear Generating Plant. Washington, D.C. ADAMS No. 

ML081840311.

Boden, Peggy J. 2008. Cultural Resources Assessment for the Prairie Island Nuclear 

Generating Plant, Goodhue County, Minnesota. St. Paul, MN. The 106 Group Ltd. –

Archaeological Report. Non-public reference per 36 CFR 800.11(c), NHPA § 304[16 U.S.C. 
Affected Environment 

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470w-3(a) — Confidentiality of the location of sensitive historic resources], and Minnesota 

Statute 307.08, Sub. 11. 

Boden, Peggy J. (Boden). 2009. Re: Phase I Cultural Resources Reconnaissance Survey for 

the Holding Pond Expansion Project, Prairie Island Nuclear Generating Plant, Goodhue County. 

Merjent, Inc. Letter report submitted to Major Projects-Nuclear, Prairie Island Nuclear 

Generating Plant. 

Boden, Peggy J., David Maki, and Geoffrey Jones. (Boden et. al). 2010. A Limited 

Archaeological Reconnaissance Survey of the Grounds of the Prairie Island Nuclear Generating 

Plant, Red Wing, Goodhue County, Minnesota. Merjent, Inc. Submitted to Xcel Energy. Final 

Report 

CAA (Clean Air Act. 42 U.S.C. 7401, et seq.). United States Code, Title 42, The Public Health 

and Welfare, Chapter 85, “Air Pollution Prevention and Control.” 

City of Red Wing. 2003. “City History.” Available URL: http://www.red-wing.org (accessed: 

March 1, 2009). 

Cornell (Cornell Lab of Ornithology). 2003. “Peregrine Falcon.” Available URL: 

http://www.birds.cornell.edu/AllAboutBirds/BirdGuide/Peregrine_Falcon_dtl.html. Accessed 

October 2, 2007. ADAMS No. ML073300303. 

Cowdery, Timothy K. 1999. Water Resources of the Prairie Island Indian Reservation, 

Minnesota, 1994-1997: Water-Resources Investigation Report 99-4069. U.S. Geological 

Survey. Available URL: http://mn.water.usgs.gov/pubs/99-4069.pdf (accessed October 10, 

2008). 

CWA (Clean Water Act; or Federal Water Pollution Control Act). 33 U.S.C. 1251 et seq. 

Dakota County. 1999. Dakota County 2020 Land Use Policy Plan. October. Available URL: 

http://www.co.dakota.mn.us/NR/rdonlyres/000008fa/ckgrsunrmqgcekbkcouzfbchsucsbdwg/3Lan

dUse.pdf (accessed December 29, 2008). 

Dakota County. 2005. Environmental and Natural Resource Management Policy Plan, Dakota 

County Comprehensive Plan. October 4. Available URL: 

http://www.co.dakota.mn.us/NR/rdonlyres/00001137/gkcoqwzasmhkzybxqpfbblfowhmsfcek/6En

vNaturalResources905.pdf?bcsi_scan_A3171404B2C9D30E=0&bcsi_scan_filename=6EnvNatu

ralResources905.pdf (accessed December 29, 2008). 

Dobbs, Clark A. 1988. Outline of Historic Contexts for the Prehistoric Period (ca. 12,000 B.P. - 

A.D. 1700): A Document in the Series Minnesota History in Sites and Structures. Reports of 

Investigations, Nos. 37 et seq. Minneapolis: Institute of Minnesota Archaeology. Prepared for 

the Minnesota State Historic Preservation Office, St. Paul. 

DOI (U.S. Department of Interior). 2010. Letter from M. Chezik, Regional Environmental Officer. 

Issuance of Renewed Operating Licenses DPR-42 and DPR-60 for Prairie Island Nuclear 

Generating Plant, Units 1 and 2. January 27, 2010. ADAMS No. ML100690175. 

Ecological Specialists (Ecological Specialists, Inc.). 2009. Final Report: Unionid Survey, 

Mississippi River Mile 798. Prepared by Barr Engineering Company, Minneapolis, Minnesota. 

July 2009. (Reference contained in Xcel 2010.) ADAMS No. ML102460533. 

EPA (U.S. Environmental Protection Agency). 1974. Information on Levels of Environmental 

Noise Requisite to Protect Public Health and Welfare with an Adequate Margin of Safety. Report 

550/9-74-004, Washington, D.C. Available URL: 

http://www.nonoise.org/library/levels74/levels74.htm (accessed March 2, 2009). 
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EPA (U.S. Environmental Protection Agency). 2006. “Mississippi River Basin & Gulf of Mexico 

Hypoxia Upper Mississippi: Background on Upper Mississippi River Basin.” Available URL 

www.epa.gov/msbasin/subbasins/upper/index.htm (accessed October 10, 2008).

EPA (U.S. Environmental Protection Agency). 2007. Hazardous Waste Generators Regulations. 

May. Available URL: http://www.epa.gov/osw/hazard/downloads/tool.pdf (accessed January 16, 

2009). ADAMS No. ML082880301.

EPA (U.S. Environmental Protection Agency). 2007a. “Wastes – Laws and Regulations.”

Available URL: http://www.epa.gov/osw/laws-regs/index.htm (accessed January 16, 2009).

ADAMS No. ML082880301.

EPA (U.S. Environmental Protection Agency). 2008a. “Environmental Management Systems 

(EMS).” Available URL: http://www.epa.gov/ems/index.html (accessed January 16, 2009). 

ADAMS No. ML082880301.

EPA (U.S. Environmental Protection Agency). 2008b. “Safe Drinking Water Information 

System, County Search – Goodhue, Dakota, and Pierce Counties – October 31, 2008.” 

Available URL: http://www.epa.gov/enviro/html/sdwis/sdwis_query.html (accessed December 

19, 2008).

EPA (U.S. Environmental Protection Agency). 2009. “EPA EnviroFacts Warehouse – Facility 

Detail Report – Northern States Power Company.” Available URL: 

http://iaspub.epa.gov/enviro/fii_query_dtl.disp_program_facility?pgm_sys_id_in=MND04953778

0&pgm_sys_acrnm_in=RCRAINFO (accessed January 16, 2009). ADAMS No. ML090160473.

ESA (Endangered Species Act). 16 U.S.C. 1531, et seq.

ESWQD (Environmental Services Water Quality Department). 2005. Prairie Island Nuclear 

Generating Plant Environmental Monitoring and Ecological Studies Program. Annual Report. 

ADAMS No. ML083120223.

FWS (U.S. Fish and Wildlife Service). 2000a. Biological Opinion for the Operation and 

Maintenance of the 9-Food Navigation Channel on the Upper Mississippi River System. U.S. 

Fish and Wildlife Service, Division of Endangered Species, Fort Snelling, Minnesota. Available 

URL: http://www.fws.gov/midwest/endangered/section7/umrbofinal.pdf (accessed September 

25, 2008).

FWS (U.S. Fish and Wildlife Service). 2000b. “Threatened and Endangered Species: Prairie 

Bush Clover (Lespedeza leptostachya).” Available URL: 

http://www.fws.gov/midwest/endangered/plants/pdf/lelefctsht.pdf (accessed July 10, 2008). 

ADAMS No. ML082760088.

FWS (U.S. Fish and Wildlife Service). 2002a. Status Assessment Report for the Sheepnose, 

Plenthobasus cyphyus, Occurring in the Mississippi River System (U.S. Fish and Wildlife 

Service Regions 3, 4, 5, and 6). Ohio River Valley Ecosystem Team, Ashville, North Carolina. 

December. Available URL: 

http://www.fws.gov/midwest/mussel/documents/plethobasus_status.pdf (accessed October 15, 

2008).

FWS (U.S. Fish and Wildlife Service). 2002b. Status Assessment Report for the Spectaclecase, 

Cumberlandia monodonta, Cccurring in the Mississippi River System (U.S. Fish and Wildlife 

Service Regions 3, 4, 5, and 6). Ohio River Valley Ecosystem Team, Ashville, North Carolina. 

December. Available URL: http://www.fws.gov/midwest/mussel/documents/ 

cumberlandia_status.pdf (accessed December 3, 2008).
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FWS (U.S. Fish and Wildlife Service). 2004a. Higgins Eye Pearlymussel (Lampsilis higginsii) 

Recovery Plan: First Revision. Ft. Snelling, Minnesota. 126 pp. Available URL: 

http://ecos.fws.gov/docs/recovery_plans/2004/040714.pdf (accessed August 27, 2008).

FWS (U.S. Fish and Wildlife Service). 2004b. “Winged mapleleaf.” Available URL: 

http://www.fws.gov/Midwest/endangered/clams/pdf/wmapleleaf.pdf (accessed December 3, 

2008). ADAMS No. ML083380487.

FWS (U.S. Fish and Wildlife Service). 2008a. “County Distribution of Minnesota’s Federally 

Threatened, Endangered, and Candidate Species.” Available URL: 

http://www.fws.gov/midwest/endangered/lists/mn08cty.pdf (accessed July 9, 2008). ADAMS No. 

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FWS (U.S. Fish and Wildlife Service). 2008b. Letter from D. Sullins, Field Supervisor, U.S. Fish 

and Wildlife Service, to R. Franovich, Branch Chief. Subject: Request for list of Federally 

protected species within the area under evaluation for the Prairie Island Nuclear Generating 

Plant, Units 1 and 2, license renewal application review. August 13, 2008. ADAMS No. 

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FWS (U.S. Fish and Wildlife Service). 2008c. “Minnesota Dwarf Trout Lily (Erythronium 

propullans) Fact Sheet.” Available URL: 

http://www.fws.gov/midwest/endangered/plants/dwarftro.html (accessed July 10, 2008). ADAMS 

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FWS (U.S. Fish and Wildlife Service). 2008d. “Wetlands Digital Data: Wetlands Mapper.” 

Available URL: http://wetlandsfws.er.usgs.gov/NWI/index.html (accessed July 2, 2008). ADAMS 

No. ML082760098.

FWS (U.S. Fish and Wildlife Service). Undated. “Fact Sheet: Upper Mississippi River: National 

Wildlife and Fish Refuge.” Available URL: 

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ADAMS No. ML082760100.

FWS (U.S. Fish and Wildlife Service). Undated b. “Upper Mississippi River National Wildlife and 

Fish Refuge.” Available URL: http://www.fws.gov/refuges/profiles/index.cfm?id=32579 

(accessed July 8, 2008). ADAMS No. ML082760103.MNDNR (Minnesota Department of Natural 

Resources). 2006a. “2005 Minnesota Bald Eagle Surveys Summary.” Available URL: 

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Gibbon, Guy E. 1979. “The Mississippian Occupation of the Red Wing Area.” Minnesota 

Prehistoric Archaeology. Series, 13. St Paul: Minnesota Historical Society.

Gibbon, Guy E. and Clark A. Dobbs. 1991. “The Mississippian Presence in the Red Wing Area, 

Minnesota.” New Perspectives on Cahokia: Views from the Periphery. James Stoltman, ed. 

Pp. 281-305. Monographs in World Archaeology, 2. Madison, WI: Prehistory Press. Available 

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Hildebrandt, Emily. 2008. Literature Search and Assessment of Historical and Archaeological 

Resources Impacted by Construction and Operations Activities at the Prairie Island Nuclear 

Plant, Goodhue County, Minnesota. Final Report. Submitted to Nuclear Management 

Company. Welch, Minnesota. Minnesota State University, Mankato. August. Non-public 

reference per 36 CFR 800.11(c), NHPA § 304[16 U.S.C. 470w-3(a) — Confidentiality of the 

location of sensitive historic resources], and Minnesota Statute 307.08, Sub. 11. 

Hildebrandt Iffert, Emily. 2010. Literature Search and Assessment of Historical and 

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MCWG (Minnesota Climatology Working Group). 2008. “Minnesota Tornado History and 

Statistics.” Available URL: http://climate.umn.edu/doc/historical/tornadic.htm (accessed 

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divs/eh/fish/eating/genpoprivers.pdf (accessed December 2, 2008). ADAMS No. ML083370704.

MDH (Minnesota Department of Health). 2008b. Fish Consumption Guidelines for Women Who 

Are or May Become Pregnant and Children Under Age 15, Rivers. Available URL: 

http://www.health.state.mn.us/divs/eh/fish/eating/specpoprivers.pdf (accessed December 2, 

2008). ADAMS No. ML083370705.

MNHS (Minnesota Historical Society). 2009. “Historic Fort Snelling: A Brief History of Fort 

Snelling.” Available URL: http://www.mnhs.org/places/sites/hfs/history.html (accessed March 1, 

2009).

Minnesota Historical Society (MHS). 2009. “Historic Fort Snelling: A Brief History of Fort 

Snelling.” Available on line at http://www.mnhs.org/places/sites/hfs/history.html. Accessed: 

March 1, 2009. COPYRIGHT

Minnesota Administrative Rules. Chapter 7045, Hazardous Waste, Part 7045.0248 “License 

Renewal Application.” Available URL: https://www.revisor.leg.state.mn.us/rules/?id=7045.0248 

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Minnesota Administrative Rules. Chapter 7045, Hazardous Waste, Part 7045.1400 “Adoption of 

Federal Standards for Universal Waste Management.” Available URL: 

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No. ML090160439.

MNDNR (Minnesota Department of Natural Resources). 2006a. “2005 Minnesota Bald Eagle 

Surveys Summary.” Available URL: 

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8, 2008). Accessible at ML082760072.

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Natural Resources. Available URL: 

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(accessed July 1, 2008). ADAMS No. ML082760076.

MNDNR (Minnesota Department of Natural Resources). 2008. “DNR Water Appropriation 

Permits, Active Permits by County.” Available URL

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leucocephalus). Available URL: http://www.dnr.state.mn.us/birds/eagles/index.html (accessed 

September 8, 2008). ADAMS No. ML082770159.

MNDNR (Minnesota Department of Natural Resources). 2008b. Letter from H. Cyr, Minnesota 

Department of Natural Resources, to R. Franovich, Branch Chief, Division of License Renewal. 

Subject: Reply to Request for Natural Heritage Information in the Vicinity of the Prairie Island 

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Affected Environment

2-86

MNDNR (Minnesota Department of Natural Resources). 2008c. “Lost Valley Prairie SNA.” 

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ADAMS No. ML082770153.

MNDNR (Minnesota Department of Natural Resources). 2008d. “Peregrine Falcon (Falco 

peregrinus).” Available URL: http://www.dnr.state.mn.us/snapshots/birds/peregrinefalcon.html 

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MNDNR (Minnesota Department of Natural Resources). 2008e. “Savage Fen SNA.” Available 

URL: http://www.dnr.state.mn.us/snas/sna00999/index.html (accessed July 8, 2008). ADAMS 

No. ML082770155.

MNDNR (Minnesota Department of Natural Resources). 2008f. “Trumpeter Swan Life History.” 

Available URL: http://www.dnr.state.mn.us/eco/nongame/projects/trumpeterswan/lifehistory.html 

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MNDNR (Minnesota Department of Natural Resources). 2008g. “Trumpeter Swan Restoration 

Project.” Available URL: 

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Pool #3 WMA.” Available URL: 

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MPCA (Minnesota Pollution Control Agency). 2008k. “Upper Mississippi River Basin.” Available 

URL: http://www.pca.state.mn.us/water/basins/uppermiss/index.html (accessed October 10, 

2008). ADAMS No. ML083380243.

MRBDC (Minnesota River Basin Data Center). 2000. “State of the Minnesota River: Summary of 

Surface Water Quality Monitoring.” Available URL: 

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No. ML083380246.

OSA (Minnesota Office of the State Auditor). 2007. Independent Auditor's Report: Goodhue 

County, Red Wing, Minnesota, Year Ended December 31, 2006. November 29. Available URL:

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Affected Environment

2-87

http://www.demography.state.mn.us/DownloadFiles/00Proj/PopulationProjections02.pdf

(accessed August 3, 2009).

Minnesota Statute 307.08, Subd. 11. Private Cemeteries Act. – Publicly Available Statute

Mn/DOT (Minnesota Department of Transportation). “2007 Traffic Volumes General Highway 

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Mussel Coordination Team. 2005. Status of Implantation of Higgins Eye Pearlymussel 

(Lampsilis higginsii) Reasonable and Prudent Alternatives and Reasonable and Prudent 

Measures and Winged Mapleleaf (Quadrula fragosa) Reasonable and Prudent Measures.

November 2005. Available URL: http://www.fws.gov/midwest/mussel/documents/ 

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NCDC (National Climatic Data Center). 2005. “Normals, Means, and Extremes: Minneapolis, 

MN (MSP).” Available URL: 

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NEPA (National Environmental Policy Act of 1969). 42 U.S.C. 4321, et seq. 

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Units 1 and 2, “2000 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.

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Units 1 and 2, “2001 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.

NMC (Nuclear Management Company, LLC). 2003. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, “2002 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.

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Units 1 and 2, “2003 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.

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Effluent Release Report and Offsite Dose Calculation Manual, Enclosure 2, “Annual Radioactive 

Effluent Report. Supplemental information. January 01, 2003 – December 31, 2003.” Goodhue 

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Affected Environment

2-88

NMC (Nuclear Management Company, LLC). 2004b. Prairie Island Nuclear Generating Plant -

Units 1 and 2, Operating License No.DPR-42, DPR-60. Annual Radioactive Effluent Release 

Report and Offsite Dose Calculation Manual, Enclosure 3, “Effluent and Waste Disposal Annual 

Report. Solid Waste and Irradiated Fuel Shipments. January 01, 2003 – December 31, 2003.” 

Goodhue County, Minnesota. ADAMS No. ML041420504.

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Units 1 and 2, “2004 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.

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Units 1 and 2, Operating License No.DPR-42, DPR-60 and SNM-2506. Annual Radioactive 

Effluent Release Report and Offsite Dose Calculation Manual, Enclosure 2, “Annual Radioactive 

Effluent Report. Supplemental information. January 01, 2004 – December 31, 2004.” Goodhue 

County, Minnesota. ADAMS No. ML051360426.

NMC (Nuclear Management Company, LLC). 2005b. Prairie Island Nuclear Generating Plant -

Units 1 and 2, Operating License No.DPR-42, DPR-60. Annual Radioactive Effluent Release 

Report and Offsite Dose Calculation Manual, Enclosure 3, “Effluent and Waste Disposal Annual 

Report. Solid Waste and Irradiated Fuel Shipments. January 01, 2005 – December 31, 2005.” 

Goodhue County, Minnesota. ADAMS No. ML051360426.

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Management Company, LLC, to E. McRee, Tetra Tech NUS, Inc. Subject: Additional Water 

Data for 2005 for Unpermitted Well. August 24, 2006. ADAMS No. ML083120227.

NMC (Nuclear Management Company, LLC). 2006z. Prairie Island Nuclear Generating Plant 

Operations Manual, Section D14.6, “Storm Water Pollution Prevention Plan.” March 2006.

ADAMS No. ML028806950.

NMC (Nuclear Management Company, LLC). 2006s. Prairie Island Nuclear Generating Plant 

Radiation Environmental Monitoring Program Annual Report to the U.S. Nuclear Regulatory 

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ML083120233.

NMC (Nuclear Management Company, LLC). 2006q. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, “2005 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.

NMC (Nuclear Management Company, LLC). 2006b. Prairie Island Nuclear Generating Plant -

Units 1 and 2, Operating License No.DPR-42, DPR-60 and SNM-2506. Annual Radioactive 

Effluent Release Report and Offsite Dose Calculation Manual, Enclosure 2, “Annual Radioactive 

Effluent Report. Supplemental information. January 01, 2005 – December 31, 2005.” Goodhue 

County, Minnesota. ADAMS No. ML061370092.

NMC (Nuclear Management Company, LLC). 2006c. Prairie Island Nuclear Generating Plant -

Units 1 and 2, Operating License No.DPR-42, DPR-60. Annual Radioactive Effluent Release 

Report and Offsite Dose Calculation Manual, Enclosure 3, “Effluent and Waste Disposal Annual 

Report. Solid Waste and Irradiated Fuel Shipments. January 01, 2005 – December 31, 2005.” 

Goodhue County, Minnesota. ADAMS No. ML061370092.

NMC (Nuclear Management Company, LLC). 2007b. Offsite Dose Calculation Manual Changes, 

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50-282 and 50-306, Goodhue County, Minnesota. ADAMS No. ML081370318.

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Units 1 and 2, “2006 – DNR Annual Report of Water Use.” ADAMS No. ML083120233.
Affected Environment

2-89

NMC (Nuclear Management Company, LLC). 2007c. Prairie Island Nuclear Generating Plant -

Units 1 and 2, Operating License No.DPR-42, DPR-60. Annual Radioactive Effluent Release 

Report and Offsite Dose Calculation Manual, Enclosure 2, “Annual Radioactive Effluent Report. 

Supplemental information. January 01, 2006 – December 31, 2006.” Goodhue County, 

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NMC (Nuclear Management Company, LLC). 2007d. Prairie Island Nuclear Generating Plant -

Units 1 and 2, Operating License No.DPR-42, DPR-60. Annual Radioactive Effluent Release 

Report and Offsite Dose Calculation Manual, Enclosure 3, “Effluent and Waste Disposal Annual 

Report. Solid Waste and Irradiated Fuel Shipments. January 01, 2006 – December 31, 2006.” 

Goodhue County, Minnesota. ADAMS No. ML071370287.

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ML081130677, ML081130681, and ML081130684.

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Units 1 and 2, Operating License No.DPR-42, DPR-60 and SNM-2506. 2007 Annual 

Radioactive Effluent Release Report and Offsite Dose Calculation Manual, Enclosure 2, “Annual 

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Units 1 and 2, Operating License No.DPR-42, DPR-60. Annual Radioactive Effluent Release 

Report and Offsite Dose Calculation Manual, Enclosure 3, “Effluent and Waste Disposal Annual 

Report. Solid Waste and Irradiated Fuel Shipments. January 01, 2007 – December 31, 2007.” 

Goodhue County, Minnesota. ADAMS No. ML081370317.

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%20Zebra%20Mussel%20Density%20Report.doc (accessed October 9, 2008). ADAMS No.
Affected Environment

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USFS (U.S. Forest Service). Undated. “Eastern Broadleaf Forest Continental Province.” 

Available URL: http://www.fs.fed.us/colorimagemap/images/222.html (accessed July 2, 2008). 

ADAMS No. ML082760106.
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USGS (U.S. Geological Survey). 2006. Water Resources Data, Minnesota, Water Year 2005: 

Water Data Report MN-05-051. April 5, 2006. ADAMS No. ML028806950

USGS (U.S. Geologic Service). 2008. Nonindigenous Aquatic Species Fact Sheet – Dreissena

polymorpha). Available URL: http://nas.er.usgs.gov/queries/FactSheet.asp?speciesID=5 

(accessed September 10, 2008). ADAMS No. ML083380519.

WDSC (Wisconsin Demographics Services Center). 2004. Wisconsin Population 2030: A 

Report on Projects State, County and Municipal Populations and Households for the Period 

2000-2030. Madison, WI. March. Available URL:

http://www.doa.state.wi.us/docview.asp?docid=2114 (accessed August 3, 2009).

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polymorpha). Available URL: http://dnr.wi.gov/invasives/fact/ zebra.htm (accessed September 

11, 2008). ADAMS No. ML083380525.

WDPI (Wisconsin Department of Public Instruction). 2009. “Public School Enrollment Data.” 

Data set “PEM09”. Available URL: http://dpi.wi.gov/lbstat/pubdata2.html (accessed July 30, 

2009).

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URL: http://www.newadvent.org/cathen/07215c.htm (accessed March 1, 2009). 

Willis, J. W. 1914. “Minnesota.” From 1914 edition of Catholic Encyclopedia. Available on line at 

http://www.newadvent.org/cathen/10326c.htm (accessed March 1, 2009).

Winterstein, T.A. 2001. Hydraulic Properties of Mt. Simon Aquifer, Prairie Island Indian 

Community, Southeastern Minnesota: Water-Resources Investigation Report 02-4263. U.S. 

Geological Survey. Available URL: http://pubs.usgs.gov/wri/wri024263/pdf/wri024263.pdf 

(accessed December 4, 2008).

Xcel Energy Environmental Services. 2006. Xcel Energy Prairie Island Nuclear Generating 

Plant: Design and Construction Technology Plan. Submitted in accordance with the NPDES 

final regulations to establish requirements for cooling water intake structures at Phase II existing 

facilities. NPDES Permit #MN0004005. October 23, 2006.

Xcel (Xcel Energy). 2010. Letter from B. J. Sawatzke, Director, Site Operations, to NRC 

Document Control Desk. Subject: Responses to NRC Requests for Additional Information 

Dated August 27, 2010, Regarding Application for Renewed Operating Licenses. September 2, 

2010. ADAMS No. ML102460533.

3-1

3.0 ENVIRONMENTAL IMPACTS OF REFURBISHMENT

Facility owners or operators may need to undertake or, for economic or safety reasons, may 

choose to perform refurbishment activities in anticipation of license renewal or during the license 

renewal term. The major refurbishment class of activities characterized in the Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) (NRC 

1996; 1999) is intended to encompass actions that typically take place only once in the life of a 

nuclear plant, if at all. Examples of these activities include, but are not limited to, replacement of 

boiling-water reactor recirculation piping and replacement of pressurized-water reactor steam 

generators. As noted in the GEIS, refurbishment activities could result in environmental impacts 

beyond those that occur during normal plant operations. For issues that meet Category 1 

criteria, no additional plant-specific analysis is required in this supplemental environmental 

impact statement (SEIS) unless new and significant information is identified. Category 2 issues 

are those that do not meet criteria for Category 1 and, therefore, additional plant-specific review 

of these issues is required. Refurbishment activities may affect a variety of environmental issues 

as listed in Table 3-1 below. 

Table 3-1. Issues Related to Refurbishment at PINGP 1 and 2

Issues Category

Surface Water Quality, Hydrology, and Use

Impacts of refurbishment on surface water quality 1

Impacts of refurbishment on surface water use 1

Aquatic Ecology

Refurbishment 1

Terrestrial Resources

Refurbishment impacts 2

Threatened and Endangered Species

Threatened and Endangered Species 2

Ground Water Use and Quality

Impacts of refurbishment on ground water use and quality 1

Air Quality

Air quality during refurbishment (nonattainment and maintenance areas) 2

Land Use

Onsite land use 1

Human Health

Radiation exposures to the public during refurbishment 1
Environmental Impacts of Refurbishment

3-2

Issues Category

Occupational radiation exposures during refurbishment 1

Socioeconomics

Public Services: Public Safety, Social Services, and Tourism and Recreation 1

Aesthetic Impacts (refurbishment) 1

Housing Impacts 2

Public Services: Education (refurbishment) 2

Public Services: Public Utilities 2

Public Services: Transportation 2

Historic and Archaeological Resources 2

Offsite Land Use (refurbishment) 2

Environmental Justice

Environmental Justice Uncategorized

Northern States Power Co. (NSP) plans to replace the two steam generators at Prairie Island 

Nuclear Generating Plant, Unit 2 to support plant operations through the renewed license 

period. The steam generators used at PINGP 1 and 2 are recirculating U-tube vertical steam 

generators and will be replaced with the same type. Steam generators would only be replaced 

on Unit 2 as the Unit 1 steam generators were replaced in 2004. Accordingly, NSP and the U.S. 

Nuclear Regulatory Commission (NRC) have analyzed steam generator replacement as a 

refurbishment activity, pursuant to Title 10, Section 51.53(c)(3)(ii), of the Code of Federal 

Regulations (10 CFR 51.53(c)(3)(ii)). Unless otherwise noted, the discussion of the 

refurbishment activities is adapted from the Environmental Report (ER) (NMC 2008) or 

information gathered during NRC’s site audit.

3.1 Refurbishment Activities at PINGP 1 and 2

Steam generator replacement activities will take approximately 80 days to complete. The 

replacement steam generators would be manufactured by AREVA in Chalon Saint-Marcel, 

located in central Eastern France and will be delivered and installed in 2013. The steam 

generator replacement will be coordinated with scheduled outage maintenance and refueling. 

The replacement steam generators will be transported across the Atlantic Ocean via ship, and 

then transferred to a barge for transportation up the Mississippi River. The barge will pass 

through Lock and Dam 3 and be offloaded at the Prairie Island Nuclear Generating Plant, Units 

1 and 2 (PINGP 1 and 2) barge landing, which was used previously for the Unit 1 steam 

generator replacement in 2004. For transportation within the United States, NSP will be 

required to meet all Federal, State, and local requirements, such as those that may be 

applicable to dredge or fill activities. The U.S. Army Corps of Engineers (USACE) will regulate 

such work pursuant to Section 404 of the Clean Water Act (CWA) and Section 10 of the Rivers 

and Harbors Act of 1899 if any of the work is performed in “navigable waters.”
Environmental Impacts of Refurbishment

3-3

Once on site, the steam generators will be moved via a self-propelled transporter to a temporary 

building, which will house the replacement steam generators until they are ready for installation. 

No onsite road improvements would be required to offload the steam generators. Several 

additional temporary buildings will be constructed which may include office space for 

construction contractors and a decontamination building. This temporary construction area will 

be located approximately 100 yds (91 m) northwest of the turbine building. Warehouses may be 

built for storage purposes during the steam generator replacement and, if built, would remain 

after the steam generator replacement is complete. No construction will take place on 

previously-undisturbed land. The old steam generators will be transported offsite for disposal.

NSP estimates that additional 750 workers would be required to complete the combined 

maintenance and refueling and steam generator replacement during the September 2013 

outage.

3.2 Environmental Impacts of Refurbishment

The following sections discuss the Category 2 issues associated with refurbishment activities at 

PINGP 1 and 2. Any environmental impacts from refurbishment will be in addition to those 

associated with continued operation of PINGP 1 and 2 for the period of license renewal; 

Chapter 4 of this report discusses those issues.

3.2.1 Terrestrial Resources – Refurbishment Impacts

The terrestrial resources on and in the vicinity of the PINGP 1 and 2 site are described in 

Section 2.2.7 of this SEIS. Unless otherwise noted, the discussion of the impacts of 

refurbishment to terrestrial ecology is adapted from the ER (NMC 2008), or information gathered 

during NRC’s site audit.

The Unit 2 steam generators replacement project would likely require laydown areas and the 

construction of temporary structures. An area located approximately 300 ft (90 m) from the 

turbine building would be used for temporary construction. Temporary construction may include 

a facility to house the steam generators before the replacement, office space for construction 

contractors, and a decontamination building. Any warehouses constructed for materials storage 

would likely remain after the steam generator replacement outage. No permanent storage 

building would be built because the old steam generators would be disposed of after being 

removed from Unit 2. All construction activities associated with refurbishment would occur on 

site and would not impact any previously undisturbed areas. Any ground-disturbing activities 

that take place would require the appropriate permits from local, state, and Federal agencies.

No offsite road improvements would be required for delivery of the steam generators to PINGP 

1 and 2 as delivery of the new steam generators would not require extensive overland travel. 

The new steam generators would be offloaded from a barge to a transporter directly onto the 

PINGP 1 and 2 site.

Some noise and construction impacts may impact edge species and wildlife for the period of 

onsite activity, but these effects will likely be minimal and short term as the proposed 

refurbishment outage would last a total of approximately 80 days. No wetlands or floodplains 

would be affected by refurbishment activities.

Based on information from the staff’s independent review of NSP’s ER for the PINGP 1 and 2 

proposed license renewal, the staff’s site visit, the scoping process, and evaluation of other 

reports and information, impacts to terrestrial resources during the proposed Unit 2 steam 

generator replacement would be SMALL. A few mitigation measures that could reduce impacts 

to the terrestrial environment during construction of the temporary facilities include silt fences to 
Environmental Impacts of Refurbishment

3-4

minimize sediment transport, the use of best management practices, and revegetation of 

cleared land remaining after completion of construction. These mitigation measures could 

reduce impacts by reducing erosion and minimizing the movement of sediment, nutrients, and 

pollutants.

3.2.2 Threatened and Endangered Species

3.2.2.1 Terrestrial Species

The threatened and endangered terrestrial species on or in the vicinity of the PINGP 1 and 2 

site or along the in-scope transmission line ROWs are described in Section 2.2.7.2 of this SEIS. 

Unless otherwise noted, the discussion of the impacts of refurbishment to threatened and 

endangered terrestrial species is adapted from the ER (NMC 2008) or information gathered 

during NRC’s site audit.

As described in Section 3.2.1 above, all construction activities associated with refurbishment 

would occur on site and would not impact any previously undisturbed land, and no offsite 

overland travel or associated road improvements would be required for transportation of the 

new steam generators to the PINGP 1 and 2 site.

Minimal noise and construction impacts may impact edge species and wildlife for the period of 

onsite activity; however no threatened or endangered species will likely be impacted as a result 

of refurbishment activities. Though bald eagles (Haliaeetus leucocephalus) are known to nest 

within the vicinity of the PINGP 1 and 2 site, the species is not likely to be impacted by 

refurbishment activities because these activities will be confined to the PINGP 1 and 2 site. The 

pair of peregrine falcons (Falco peregrineus) that nest on Unit 1 are not likely to be affected by 

the proposed Unit 2 steam generator replacement because the nest is far enough from the 

ground. In addition, the steam generator replacement is not expected to cause significant noise 

or other types of disturbance to the birds. Additionally, NSP would undertake the proposed 

steam generator replacement outside of the falcon breeding period, which generally lasts from 

March through July.

Based on information from the staff’s independent review of NSP’s ER for the PINGP 1 and 2 

proposed license renewal, the staff’s site visit, the scoping process, and evaluation of other 

reports and information, impacts to threatened and endangered terrestrial species during the 

proposed Unit 2 steam generator replacement would be SMALL. 

3.2.2.2 Aquatic Species

The threatened and endangered aquatic species in the vicinity of the PINGP 1 and 2 site are 

described in Section 2.2.7.1 of this SEIS. Unless otherwise noted, the discussion of the impacts 

of refurbishment to aquatic threatened and endangered species is adapted from the ER (NMC 

2008), or information gathered during NRC’s site audit.

As described above, Unit 2 will be receiving replacement steam generators, transported up the 

Mississippi River by barge, and offloaded directly onto the PINGP 1 and 2 site. Because of the 

Lock and Dam system on the Mississippi River, designed to allow barges to navigate up the 

river, no changes to the river or dams are anticipated. Because there is already a cement pad

on the shoreline where the steam generators will be offloaded from the barge onto the plant site, 

there will be little to no change to the shoreline.

Based on information from the staff’s independent review of NSP’s ER for the PINGP 1 and 2 

proposed license renewal, the staff’s site visit, the scoping process, and evaluation of other 

reports and information, impacts to aquatic resources during the proposed Unit 2 steam 

generator replacement would be SMALL. 
Environmental Impacts of Refurbishment

3-5

3.2.3 Air Quality During Refurbishment (Non-Attainment and Maintenance Areas)

Air quality during refurbishment (nonattainment and maintenance areas) is a Category 2 issue. 

Table B-1 of Appendix A to Subpart B, “Environmental Effect of Renewing the Operating 

License of a Nuclear Power Plant,” of 10 CFR Part 51, “Environmental Protection Regulations 

for Domestic Licensing and Related Regulatory Functions,” notes the following:

Air quality impacts from plant refurbishment associated with license renewal are 

expected to be small. However, vehicle exhaust emissions could be cause for 

concern at locations in or near nonattainment or maintenance areas. The 

significance of the potential impact cannot be determined without considering the 

compliance statutes of each site and the numbers of workers expected to be 

employed during the outage.

Specifically, 10 CFR 51.53(c)(3)(ii)(F) requires the following:

If the applicant’s plant is located in or near a nonattainment or maintenance area, 

an assessment of vehicle exhaust emissions anticipated at the time of peak 

refurbishment work force must be provided in accordance with the Clean Air Act

(CAA) as amended.

The GEIS states the following:

The 1990 CAA amendments include a provision that no federal agency shall 

support any activity that does not conform to a state implementation plan 

designed to achieve the National Ambient Air Quality Standards (NAAQS) for 

criteria pollutants (sulfur dioxide, nitrogen dioxide, carbon monoxide, ozone, lead, 

and particulate matter less than 10 μm in diameter). On November 30, 1993, the 

U.S. Environmental Protection Agency (EPA) issued a final rule (58 FR 63214) 

implementing the new statutory requirements, effective January 31, 1994. The 

final rule requires that federal agencies prepare a written conformity analysis and 

determination for each pollutant where the total of direct and indirect emissions 

caused by proposed federal action would exceed established threshold emission 

levels in a nonattainment or maintenance area. An area is designated 

“nonattainment” for a criteria pollutant if it does not meet the NAAQS for the 

pollutant. A maintenance area has been redesignated by a State from 

nonattainment to attainment; the State must submit to EPA a plan for maintaining 

the NAAQS as a revision to its State Implementation Plan.

The steam generator replacement project would result in minor air quality impacts for the 

duration of the approximately 80-day period needed to complete refurbishment activities. The 

main sources of air quality impacts would be fugitive dust from construction activities associated 

with the project, and exhaust emissions from motorized equipment, and vehicles of temporary 

workers.

Although NSP plans to use the existing buildings and structures from the previously completed 

PINGP Unit 1 steam generator replacement, some additional temporary structures would be

built. These include a facility for preparing the steam generators. The construction of this facility

may result in some minor, temporary air quality impacts due to emissions and fugitive dust from 

operation of earth-moving and material handling equipment. NSP would use best management 

practices to minimize fugitive dust and emissions resulting from construction activities. (NMC 

2008)

NSP indicated that an additional 750 temporary employees would be needed for the steam 

generator replacement project which is estimated to take 80 days to complete. NSP assumed 
Environmental Impacts of Refurbishment

3-6

that the additional temporary workforce would commute from areas within PINGP 1 and 2’s 50-

miles radius. This would result in an additional 37,500 vehicle miles travelled within the county, 

which is approximately 2.12 percent of the 1,771,899 average vehicles miles per day for the 

Goodhue County in 2007. (NMC 2008)

Dakota County, located 12 miles northwest of the plant, is the closest maintenance area for 

lead, sulfur dioxide (SO2) and carbon monoxide (CO). Olmsted County, located 35 miles south 

of the PINGP 1 and 2 site, is a maintenance area for sulfur dioxide (SO2) and PM10. Since 

temporary workforce would be coming from all over the 50-mile region, the additional 37,500 

vehicle miles travelled would represent 0.35 percent of the total miles traveled in the Dakota 

County per day and approximately 1 percent of the total miles traveled in the Olmsted County 

per day, which is a very small fraction of the total miles travelled in these two counties each day.

The NRC staff concludes that the impact on air quality of vehicle exhaust emissions and 

construction activities during the PINGP Unit 2 steam generator replacement project would be 

SMALL. The NRC staff identified a variety of measures that could mitigate potential air quality 

impacts resulting from the PINGP 1 and 2, Unit 2, steam generator replacement project. These 

include the use of the best management practices and implementation of dust control plan to 

minimize emissions from construction activities, the use of multi-person vans and the 

implementation of shift changes for the workforce to reduce the number of vehicles on the road 

at any given time. NSP has expressed an interest to work with the PIIC to coordinate and 

implement appropriate measures to mitigate transportation impacts resulting from the Unit 2 

steam generator replacement project. Mitigation actions may include using NSP’s private 

access road for heavy truck traffic related to the project to reduce interference with traffic 

entering the PIIC casino and reservation property, using local law enforcement to control traffic 

during PINGP shift changes, and staggering the refurbishment work schedule, if necessary.

3.2.4 Housing Impacts

Housing impacts during refurbishment is a Category 2 issue. Table B-1 of 10 CFR Part 51, 

Subpart A, Appendix B, notes that: 

Housing impacts are expected to be of small significance at plants located in a 

medium or high population area and not in an area where growth control 

measures that limit housing development are in effect. Moderate or large 

housing impacts of the workforce associated with refurbishment may be 

associated with plants located in sparsely populated areas or in areas with 

growth control measures that limit housing development.

NSP estimates that steam generator replacement would require a one-time increase in the 

number of refueling outage workers for up to 80 days at PINGP 1 and 2. Approximately 750 

workers would be needed to the perform PINGP 1 and 2, Unit 2, steam generator replacement 

project activities in addition to the normal number of refueling outage workers (NMC 2008).

The number of additional workers would cause a short-term increase in the demand for 

temporary (rental) housing units in the region beyond what is normally experienced during a

refueling outage at PINGP 1 and 2. Since PINGP 1 and 2 are located in a high population area 

(see Section 2.2.8.5) and the number of available housing units has kept pace or exceeded 

changes in county populations (see Section 2.2.8.1), any changes in employment would have 

no noticeable effect on the availability of housing in the socioeconomic region of influence 

(ROI). Because of the short duration of the steam generator replacement activity and the 

availability of housing in the region, employment-related housing impacts would have no 

noticeable impact.
Environmental Impacts of Refurbishment

3-7

3.2.5 Public Services – Education (Refurbishment)

Education is a Category 2 refurbishment issue. Table B-1 of 10 CFR Part 51, Subpart A, 

Appendix B, notes that “[m]ost sites would experience impacts of small significance but larger 

impacts are possible depending on site- and project-specific factors.”

As discussed in Section 3.2.4, NSP estimates that the PINGP 1 and 2, Unit 2, steam generator 

replacement would require a one-time increase in the number of refueling outage workers for up 

to 80 days at the PINGP 1 and 2 site (NMC 2008). Because of the short duration of the steam 

generator replacement activity, workers would not be expected to bring families and school-age 

children with them; therefore, there would be no impact on educational services during this 

extended refueling outage.

3.2.6 Public Services – Public Utilities

Public utilities refurbishment is a Category 2 issue. Table B-1 of 10 CFR Part 51, Subpart A, 

Appendix B, notes that “[a]n increased problem with water shortages at some sites may lead to 

impacts of moderate significance on public water supply availability.”

Since there is no water shortage in the region and the public water systems in Goodhue County,

Dakota County, and Pierce County have excess capacity, any changes in PINGP 1 and 2 

employee water usage would have little noticeable affect on public water supply availability in 

these counties.

As discussed in Section 3.2.4, NSP estimates that the PINGP 1 and 2, Unit 2, steam generator 

replacement would require a one-time increase in the number of refueling outage workers for up 

to 80 days at the PINGP 1 and 2 site (NMC 2008). The additional number of refueling outage 

workers needed to replace the steam generators would cause a short-term increase in the 

amount of public water and sewer services used in the immediate vicinity of PINGP 1 and 2. 

Since the region has excess water supply capacity with no restrictions, this replacement activity 

would create no noticeable impact.

3.2.7 Public Services – Transportation

Transportation is a Category 2 refurbishment issue. Table B-1 of 10 CFR Part 51, Subpart A, 

Appendix B, notes that:

Transportation impacts (level of service) of highway traffic generated during plant 

refurbishment and during the term of the renewed license are generally expected 

to be of small significance. 

However, the increase in traffic associated with additional workers and the local 

road and traffic control conditions may lead to impacts of moderate or large 

significance at some sites.

As previously discussed in Section 2.2.8.2, the primary access road to PINGP 1 and 2 is County 

Road 18, which is mostly rural and uncongested. PINGP 1 and 2 have one plant access road 

via Sturgeon Lake Road and County Road 18. County Road 18 and Sturgeon Lake Road are 

also access routes to the Prairie Island Indian Community’s (PIIC) residential areas, 

government offices, health clinics, and gaming enterprise, Treasure Island Resort and Casino, 

located just off Sturgeon Lake Road east of the plant access road (PIIC 2009). NSP employees 

have the option of exiting the site via Wakonade Drive or the plant access road to Sturgeon 

Lake Road and County Road 18. Traffic at the intersections of the plant access road and 

Sturgeon Lake Road, Wakonade Drive and Sturgeon Lake Road, and Sturgeon Lake Road and 

County Road 18 are controlled by stop signs. Steam generator replacement and refueling 
Environmental Impacts of Refurbishment

3-8

outage workers would use the same entrance and exit roads as current PINGP 1 and 2 

employees.

County Road 18 and Sturgeon Lake Road currently have the capacity to handle the additional 

volume of traffic. However, due to the lack of timed traffic signals, there could be problems with 

traffic flow along Sturgeon Lake Road during the PINGP 1 and 2 site refueling outage shift 

changes. Increased traffic volumes during refueling outages at the PINGP 1 and 2 site, 

occurring approximately every 20 months, has affected the level of service capacity on Sturgeon 

Lake Road for short periods of time.

Based on this information and because of the short duration of the steam generator 

replacement activity (up to 80 days), transportation (level of service and noise) impacts in the 

vicinity of PINGP 1 and 2 would be SMALL to MODERATE and would mostly occur during shift 

changes. During periods of high traffic volume (i.e., morning and afternoon shift changes), NSP 

could stagger work schedules and use NSP employees and/or local police officials to direct 

traffic entering and leaving PINGP 1 and 2 to minimize level of service impacts on Sturgeon 

Lake RoadNSP has expressed a willingness to work with the PIIC to coordinate and implement 

appropriate measures to mitigate transportation impacts resulting from the Unit 2 steam 

generator replacement project. Mitigation actions may include using NSP’s private access road 

for heavy truck traffic related to the project to reduce interference with traffic entering the PIIC 

casino and reservation property, using local law enforcement to control traffic during PINGP 

shift changes, and staggering the refurbishment work schedule, if necessary.

3.2.8 Offsite Land Use (Refurbishment)

Offsite land use is a Category 2 refurbishment issue. Table B-1 of 10 CFR Part 51, Subpart A, 

Appendix B, notes that “impacts may be of moderate significance at plants in low population 

areas.”

Since PINGP 1 and 2 are located in a high population area, any changes in the PINGP 1 and 2 

employment would have little noticeable effect on land use in the region. Because of the short 

duration of the steam generator replacement activity, the additional number of refueling outage 

workers would not cause any permanent population- and tax revenue-related land use changes 

in the immediate vicinity of PINGP 1 and 2. The replacement of the existing steam generator 

could increase the assessed value of PINGP 1 and 2 and property tax payment could increase. 

3.2.9 Historic and Archaeological Resources

Historic and archaeological resources are a Category 2 refurbishment issue. Table B-1 of 

10 CFR Part 51, Subpart A, Appendix B, notes that:

Generally, plant refurbishment and continued operation are expected to have no 

more than small adverse impacts on historic and archaeological resources. 

However, the National Historic Preservation Act requires the Federal agency to 

consult with the State Historic Preservation Officer to determine whether there 

are properties present that require protection.

Continued operation of PINGP 1 and 2 during the license renewal term would have a SMALL to 

MODERATE impact on archaeological resources at the plant site (see section 4.4.5 for a 

detailed discussion). NSP has no plans to alter the PINGP 1 and 2 site for license renewal. 

Should plans change, further consultation would be initiated by NSP with the NRC, Minnesota 

Historical Society (MNHS), and the PIIC. Any land disturbing activities would be carried out 

under corporate procedures. 
Environmental Impacts of Refurbishment

3-9

NSP has revised its corporate procedures to ensure the protection of historic and 

archaeological resources at PINGP 1 and 2. Specifically, NSP has included detailed 

instructions for its employees to follow in the event archaeological resources are inadvertently 

discovered during ground-disturbing activities (Xcel 2009). 

NSP has indicated that the PINGP Unit 2, steam generators would be replaced. The steam 

generator replacement project would take place in an area that was previously disturbed by the 

construction of PINGP 1 and 2. Nearly all steam generator replacement activities will take 

place within the existing developed industrial portions of the plant site. Undisturbed areas of the 

plant site would not be affected (NMC 2008). NSP has contacted the MNHS and the PIIC to 

inform them of this refurbishment activity. For a map of potentially affected areas, see

Figure 3.1.

Ground disturbing activities associated with the project would include the excavation of 

previously disturbed areas in the vicinity of PINGP 1 and 2 (NMC 2008). Several temporary 

buildings would be built, which may include a facility for preparing the steam generators, office 

space for construction contractors, and a decontamination building. Warehouse(s) may be built 

within the developed portions of the plant. and would remain after the steam generator 

replacement outage (NMC 2008). No road improvements would be required because the steam 

generators would arrive via barge and be offloaded to a self-propelled transporter capable of 

traveling on existing site roads without damage. The transporter will move along an existing dirt 

service road that extends from the barge landing to PINGP Unit 2. The service road area was 

previously heavily disturbed during construction of PINGP 1 and 2and the service road was 

used also during the PINGP Unit 1 steam generator replacement. Most activities would be 

temporary and localized. 

Because any refurbishment work done would primarily be on previously disturbed land, the 

impacts associated with the replacement of the PINGP Unit 2, steam generators are not 

expected to adversely impact historic or archaeological sites located in the vicinity of PINGP 1 

and 2. Therefore, the potential impacts from this activity on historic or archaeological resources 

would be SMALL. However, there remains the potential for unknown cultural resources to be 

present in disturbed areas of the site. Should archaeological resources be encountered during 

construction, work would cease until NSP environmental personnel perform an evaluation and 

consider possible mitigation measures through consultation with the NRC, MNHS, and the PIIC. 

In addition, NSP has implemented a cultural resources management plan which would 

coordinate procedures, policies, and effectively manage and protect the archaeological sites 

and cultural resources in the vicinity of the PINGP 1 and 2 site. 

3.2.10 Environmental Justice

Due to its close proximity to PINGP 1 and 2, the PIIC could be disproportionately affected by 

steam generator replacement activities. The effects could include transportation and noise 

impacts during shift changes and the removal of the old steam generators via rail across the 

community’s only access road to the reservation (Sturgeon Lake Road). As stated in section 

3.2.8 of this SEIS, transportation impacts from refurbishment would be SMALL to MODERATE. 

These impacts could disproportionately affect the PIIC. The PIIC could also experience the 

effects of increased noise levels from steam generator replacement activities. However, these 

impacts are of short duration and are not expected to be high. NSP has expressed a 

willingness to work with the PIIC to coordinate and implement appropriate measures to mitigate 

transportation impacts resulting from the PINGP Unit 2 steam generator replacement project. 

Mitigation measures may include using NSP’s private access road for heavy truck traffic related 

to the project, using local law enforcement to control traffic during PINGP shift changes, and 

staggering the refurbishment work schedule, if necessary.
Environmental Impacts of Refurbishment

3-10

3.3 Evaluation of New and Potentially Significant Information on Impacts of 

Refurbishment 

For all Category 1 issues related to refurbishment, the NRC staff has not identified any new and 

significant information during its review of the PINGP 1 and 2 ER, the staff’s environmental site 

audit, the scoping process, or the evaluation of other available information, including the site 

audit during the week of August 18, 2008, during which NSP’s refurbishment plans were 

discussed. Therefore, the NRC staff adopts the findings in the GEIS for Category 1 issues 

associated with refurbishment, and concludes that there would be no environmental impacts 

during the renewal term beyond those discussed in the GEIS for these issues.

3.4 Summary of Impacts of Refurbishment

For the nine Category 2 issues and environmental justice, the impacts of refurbishment at 

PINGP 1 and 2 range from no impact to a MODERATE impact. For the refurbishment issues 

Public Services: Education, Offsite Land Use, and Environmental Justice, the NRC staff 

concludes that there would be a SMALL to MODERATE impact. For the refurbishment issues 

Terrestrial Ecology, Threatened or Endangered Species, Air Quality (Nonattainment and 

Maintenance Areas), Housing Impacts, Public Services: Public Utilities, Public Services: 

Transportation, and Historic and Archeological Resources, the NRC staff concludes that the 

potential environmental effects are SMALL to MODERATE.
Environmental Impacts of Refurbishment

3-11

Figure 3-1. Potential Areas Impacted by Unit 2 

Steam Generator Replacement (Source: NMC 2008)
Environmental Impacts of Refurbishment

3-12

3.5 References

10 CFR 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental Protection 

Regulations for Domestic Licensing and Related Regulatory Functions.”

40 CFR 51.850. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

“Requirements for Preparation, Adoption, and Submittal of Implementation Plans.”

58 FR 63214. U.S. Environmental Protection Agency. Final General Conformity Regulations. 

November 30, 1993.

AREVA. 2006. “Press Release: AREVA Wins Contract for Two Replacement Steam Generators 

at Prairie Island Nuclear Generating Plant.” Available URL: http://www.arevanp.com/scripts/press/publigen/content/templates/show.asp?P=795&L=US (accessed November 

25, 2008). ADAMS No. ML083310148.

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NRC (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, Washington, D.C. 

ADAMS Nos. ML040690705 and ML040690738.

NRC (U.S. Nuclear Regulatory Commission). 1999. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, Main Report, “Section 6.3-Transportation, table 9.1, 

Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final 

Report.” NUREG-1437, Volume 1, Addendum 1, Washington, D.C.

PIIC (Prairie Island Indian Community). 2008. Information provided by the Prairie Island Indian 

Community (PIIC) will aid NRC staff in the preparation of the Supplemental EIS (SEIS). PIIC 

Supplemental Information. Non-public reference per 36 CFR 800.11(c).

PIIC (Prairie Island Indian Community). 2009. Information provided by the Prairie Island Indian 

Community (PIIC). PIIC Supplemental Information. Non-public reference per 36 CFR 800.11(c).

Xcel (Xcel Energy). 2009. Letter from M. Wadley, Site Vice President, Prairie Island Nuclear 

Generating Plant, Units 1 and 2, Welch, Minnesota, to U.S. Nuclear Regulatory Commission, 

Washington, D.C. Subject: Reply to Revisions to Environmental Report Regarding Application 

for Renewed Operating Licenses. March 4, 2009. ADAMS No. ML090750915
4-1

4.0 ENVIRONMENTAL IMPACTS OF OPERATION

This chapter addresses potential environmental impacts related to the period of extended 

operation of Prairie Island Nuclear Generating Plant, Units 1 and 2 (PINGP 1 and 2). These 

impacts are grouped and presented according to resource. Generic issues (Category 1) rely on 

the analysis provided in the Generic Environmental Impact Statement for License Renewal of

Nuclear Power Plants (GEIS) prepared by the U.S. Nuclear Regulatory Commission (NRC) 

(NRC 1996; 1999) and are discussed briefly. NRC staff analyzed site-specific issues (Category 

2) for PINGP 1 and 2 and assigned them a significance level of SMALL, MODERATE, or 

LARGE. Some remaining issues are not applicable to PINGP 1 and 2 because of site 

characteristics or plant features. Section 1.4 of this report explains the criteria for Category 1 

and Category 2 issues and defines the impact designations of SMALL, MODERATE, and 

LARGE.

4.1 Land Use

Land use issues are listed in Table 4-1. The staff did not identify any Category 2 issues for land 

use. The staff also did not identify any new and significant information during the review of the 

applicant’s environmental report (ER) (NMC 2008), the site audit, or the scoping process. 

Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. 

For these issues, the GEIS concludes that the impacts are SMALL, and additional site-specific 

mitigation measures are not likely to be warranted.

Table 4-1. Land Use Issues. Section 2.2.1 of this report describes the land use around 

PINGP 1 and 2.

Issues GEIS Section Category

Onsite land use 4.5.3 1

Power line right-of-way 4.5.3 1

4.2 Air Quality

The air quality issue applicable to PINGP 1 and 2 is listed in Table 4-2. The staff did not identify 

any Category 2 issues for air quality. The staff also did not identify any new and significant 

information during the review of the applicant’s ER (NMC 2008), the site audit, or the scoping

process. Therefore, there are no impacts related to this issue beyond those discussed in the 

GEIS. For these issues, the GEIS concludes that the impacts are SMALL, and additional sitespecific mitigation measures are not likely to be warranted.

Table 4-2. Air Quality Issue. Section 2.2.2 of this report describes air quality in the 

vicinity of PINGP 1 and 2.

Issue GEIS Section Category

Air quality effects of transmission lines 4.5.2 1
Environmental Impacts of Operation

4-2

4.3 Ground Water

The following sections discuss the Category 2 ground water issues applicable to PINGP 1 and 

2, which are listed in Table 4-3.

Table 4-3. Ground Water Use and Quality Issues. Section 2.2.3 of this report 

discussed ground water use and quality at PINGP 1 and 2.

Issues GEIS Section Category

Ground Water use conflicts (potable and service water, plants 

using >100 gpm) 4.8.1.1 2

Ground Water use conflicts (plants using cooling towers 

withdrawing make-up water from a small river) 4.8.1.3 2

4.3.1 Ground Water Use Conflicts (plants using >100 gpm)

NRC specifies as issue 33 in 10 CFR 51, Subpart A, Appendix B, Table B-1, that “[if] the 

applicant’s plant...pumps more than 100 gallons [6.3 x 10-3 m3

/day] (total onsite) of ground 

water per minute (gpm), an assessment of the impact of the proposed action on ground water

use must be provided.” The NRC further states in 10 CFR 51.53(c)(3)(ii)(C), that “plants that use 

more than 100 gpm may cause ground water use conflicts with nearby ground water users.”

This applies to PINGP 1 and 2 because, as discussed in section 2.2.3.1 of this report, though

PINGP 1 and 2 averaged 92 gpm (5.8 x 10-3 m3

/s) annually from 2000 to 2005, in 2005, PINGP 

1 and 2 pumped 118 gpm (7.4 x 10-3 m3

/day). 

A ground water withdrawal rate of over 100 gpm (6.3 x 10-3 m3

/day) has the potential to create a 

cone of depression large enough to affect offsite wells and ground water supplies, limiting the 

amount of ground water available for the plant’s surrounding areas. To determine potential 

impacts, the drawdown rate of 2005 ground water use was calculated as if it were pumped from 

a single onsite well. Using conservative values for recharge, a drawdown of 0.4 ft (0.1 m) for a 

2100 ft (640 m) radius during the plant’s first 10 operating years was calculated. No additional 

drawdown would occur during the license renewal period. (TtNUS 2006)

In addition to these calculations, most nearby offsite wells draw water from the Mount Simon 

aquifer in the Dresbach formation, while PINGP 1 and 2 draws water from the much shallower 

alluvial aquifer. The Cowdery (1999) study indicates these aquifers have minimal water 

exchange, so water drawn from the surficial aquifer is not expected to impact water drawn from 

the Mount Simon aquifer.

After reviewing the information provided by the applicant as well as the drawdown calculations, 

which show no effect on nearby ground water wells during the license renewal period, the 

impacts on nearby ground water users will be SMALL.

4.3.2 Ground Water Use Conflicts (make-up from a small river)

NRC specifies in 10 CFR 51.53(c)(3)(ii)(A) that “if the applicant’s plant utilizes cooling towers or 

cooling ponds and withdraws makeup water from a river whose annual flow rate is less than 

3.15 x 1012 cubic feet per year (ft3

/yr) [99,885 cubic feet per second (cfs)]... [t]he applicant shall 

also provide an assessment of the impacts of the withdrawal of water from the river on alluvial 

aquifers during low flow.” For water use conflicts, the NRC further states as issue 34 in 

10 CFR Part 51, Subpart A, Appendix B, Table B-1, that “...[w]ater use conflicts may result from 
Environmental Impacts of Operation

4-3

surface water withdrawals from small water bodies during low flow conditions which may affect 

aquifer recharge, especially if other ground water or upstream surface water users come online 

before the time of license renewal...” This issue is applicable to PINGP 1 and 2 because the

plant uses cooling towers, and makeup water for its cooling systems is withdrawn from the 

Mississippi River, which has an annual mean flow of approximately 18,380 cfs (5.8 x 1011 ft3

/yr;

8.25 x 106 gpm), thus meeting the NRC’s definition of a small river (TtNUS 2006). Flow is 

monitored at the Prescott U.S. Geological Survey (USGS) Station, upstream of the PINGP 1 

and 2 site.

Consumptive water losses at PINGP 1 and 2 comprise a small fraction of the Mississippi River 

flow at Lake Sturgeon where PINGP 1 and 2 are situated. PINGP 1 and 2 withdraws surface 

water at an average rate of 381,031 gpm (849 cfs; 24 m3

/s), which is about 11 percent of the 

lowest annual mean flow of the Mississippi River and approximately 4.6 percent of the average 

river flow. The rate of consumptive water use at the plant is 39 cfs (1.1 m3

/s), which is the 

recorded difference between the plant’s surface water withdrawal and the blowdown discharge 

from the plant back to the Mississippi. The consumptive use of PINGP 1 and 2 is only 0.2 

percent of the average annual flow of the Mississippi River, and 0.5 percent of the lowest annual 

mean recorded at the Prescott USGS monitoring station. (TtNUS 2006)

After reviewing the information provided by the applicant as well as the consumptive use 

calculations above, the NRC staff concludes that the impacts from consumptive water use on 

ground water would be SMALL.

4.4 Surface Water

The following sections discuss the surface water quality issues applicable to PINGP 1 and 2, 

which are listed in Table 4-4. For the Category 1 issues, the staff did not identify any new and 

significant information during the review of the applicant’s ER (NMC 2008), the site audit, or the 

scoping process. Therefore, no impacts are related to these issues beyond those discussed in 

the GEIS. For these issues, the GEIS concludes that the impacts are SMALL, and additional 

site-specific mitigation measures are not likely to be warranted.

Table 4-4. Surface Water Quality Issues. Section 2.2.4 of this report describes 

surface water quality conditions at PINGP 1 and 2.

Issues GEIS Section Category

Altered current patterns at intake and discharge structures 4.2.1.2.1 1

Altered salinity gradients 4.2.1.2.2 1

Temperature effects on sediment transport capacity 4.2.1.2.3 1

Scouring caused by discharged cooling water 4.2.1.2.3 1

Eutrophication 4.2.1.2.3 1

Discharge of chlorine or other biocides 4.2.1.2.4 1

Discharge of sanitary wastes and minor chemical spills 4.2.1.2.4 1

Discharge of other metals in wastewater 4.2.1.2.4 1

Water use conflicts (plants with cooling ponds or cooling 

towers using make-up water from a small river with low flow) 4.3.2.1; 4.4.2.1 2
Environmental Impacts of Operation

4-4

4.4.1 Water Use Conflicts

NRC specifies in 10 CFR 51.53(c)(3)(ii)(A) that “if the applicant’s plant uses cooling towers or 

cooling ponds and withdraws makeup water from a river whose annual flow rate is less than 

3.15 x 1012 ft

3

/yr (99,885 cfs), an assessment of the impact of the proposed action on the flow of 

the river and related impacts on instream and riparian ecological communities must be 

provided.” For water use conflicts, the NRC further states as issue 13 in 10 CFR Part 51, 

Subpart A, Appendix B, Table B-1, “[the] issue has been a concern at nuclear power plants with 

cooling ponds and at plants with cooling towers. Impacts on instream and riparian communities 

near these plants could be of moderate significance in some situations.” This issue is applicable 

to PINGP 1 and 2 because the plant uses a cooling tower-based heat dissipation system, and 

makeup water to replace that lost to evaporation in the cooling system is withdrawn from the 

Mississippi River, which has an annual mean flow of approximately 18,380 cfs (5.8 x 1011 ft3

/yr;

8.25 x 106 gpm), thus meeting the NRC’s definition of a small river (TtNUS 2006).

The GEIS considered surface water use conflicts to be a Category 2 issue for two separate 

reasons: 

1) Consumptive water use can adversely affect riparian vegetation and instream 

aquatic communities in the stream. Reducing the amount of water available 

to either the riparian zones or instream communities could result in impacts to 

threatened and endangered species, wildlife, and recreational uses of the

water body. In addition, riparian vegetation performs several important 

ecological functions, included stabilizing channels and floodplains, influencing 

water temperature and quality, and providing habitat for aquatic and 

terrestrial wildlife.

2) Continuing operation of these facilities depends on the availability of water 

within the river from which they are withdrawing water. For facilities that are 

located on small bodies of water, the volume of water available is expected to 

be susceptible to droughts and to competing water uses within the basin. In 

cases of extreme drought, these facilities may be required to curtail 

operations if the volume of water available is not sufficient.

An additional potential effect of the withdrawal of water from a small river is that withdrawal may 

have an impact on ground water levels and, therefore, result in ground water use conflicts (NRC 

1996). This is considered to be a separate Category 2 issue and is evaluated in Section 4.3.2 of 

this report. 

Withdrawal from PINGP 1 and 2 is about 11 percent of the lowest annual mean flow of the 

Mississippi River and approximately 4.6 percent of the average river flow. The rate of 

consumptive water use is only 0.2 percent of the average annual flow of the Mississippi River 

and 0.5 percent of the lowest annual mean recorded at the Prescott USGS monitoring station. 

These consumptive losses are insignificant relative to the flow in the Mississippi River and 

would not be expected to impact the river’s aquatic and riparian ecological communities or the 

alluvial water bearing material (aquifers).

The NRC staff reviewed available information, including that provided by the applicant, 

additional Minnesota Department of Natural Resources (MNDNR) data, information gathered at 

the site audit and through the scoping process, and other available sources. Considering PINGP

1 and 2’s small consumptive water use relative to the flows in the Mississippi River, the NRC 

staff concludes that the impact of water use on the Mississippi River at PINGP 1 and 2 would be 

SMALL. 
Environmental Impacts of Operation

4-5

4.5 Aquatic Resources

The Category 1 and Category 2 issues related to aquatic resources applicable to PINGP 1 and 

2 are discussed below and listed in Table 4-5. 

Table 4-5. Aquatic Resources Issues. Section 2.1.6 of this report describes the 

PINGP 1 and 2 cooling water system; Section 2.2.5 describes the aquatic resources.

Issues GEIS Section Category

For All Plants

Accumulation of contaminants in sediments or biota 4.2.1.2.4 1

Entrainment of phytoplankton and zooplankton 4.2.2.1.1 1

Cold shock 4.2.2.1.5 1

Thermal plume barrier to migrating fish 4.2.2.1.6 1

Distribution of aquatic organisms 4.2.2.1.6 1

Premature emergence of aquatic insects 4.2.2.1.7 1

Gas supersaturation (gas bubble disease) 4.2.2.1.8 1

Low dissolved oxygen in the discharge 4.2.2.1.9 1

Losses from predation, parasitism, and disease among 

organisms exposed to sublethal stresses 4.2.2.1.10 1

For Plants with Once-Through Heat Dissipation Systems

Entrainment of fish and shellfish in early life stages 4.3.3 2

Impingement of fish and shellfish 4.3.3 2

Heat shock 4.3.3 2

4.5.1 Generic Aquatic Ecology Issues

The NRC staff did not identify any new and significant information related to Category 1 aquatic 

issues during the review of the applicant’s ER (NMC 2008), the site audit, or the scoping

process. Therefore, there are no impacts related to these issues beyond those discussed in the 

GEIS. For these issues, the GEIS concludes that the impacts are SMALL, and additional sitespecific mitigation measures are not likely to be warranted.

4.5.2 Entrainment and Impingement

For power plants with once-through cooling systems, the impingement of fish and shellfish on 

screens associated with plant cooling systems and the entrainment of fish and shellfish in early 

life stages by plant cooling systems are considered Category 2 issues, which require a sitespecific assessment before license renewal. PINGP 1 and 2 operate in a closed-cycle mode 

part of the year, during which time impingement and entrainment are considered a Category 1 

issue. The helper-cycle mode is not discussed in the GEIS (NRC 1996), nor is it classified as 

either a Category 1 or 2 issue. To be conservative, the NRC staff considered impingement and 

entrainment at PINGP 1 and 2 as a Category 2 issue and undertook an assessment of 

impingement and entrainment for the entire year under all three operating modes. To perform 

this evaluation, the NRC staff reviewed the applicant’s ER (NMC 2008) and related documents, 

including the Clean Water Act (CWA) Section 316 demonstrations (NUS Corporation 1976; Xcel 
Environmental Impacts of Operation

4-6

Energy Environmental Services 2006) and visited the PINGP 1 and 2 site. The NRC staff also 

reviewed the applicant’s most recent National Pollutant Discharge Elimination System (NPDES)

Permit No. MN0004006 issued on June 30, 2006, by the Minnesota Pollution Control Agency 

(MPCA).

Section 316(b) of the CWA requires that the location, design, construction, and capacity of the 

cooling water intake structures reflect the best technology available for minimizing adverse 

environmental impacts (33 USC 1326). Impingement and entrainment of fish and shellfish by 

the cooling water system is a potential adverse environmental impact that can be minimized by 

the use of the best technology available.

The original 316(b) demonstration for PINGP 1 and 2 was submitted to MPCA in 1976 (NUS 

Corporation 1976). At this time, the plant was designed to operate in the three cooling modes 

(closed, helper, open), but only operated in closed-cycle mode “to the maximum extent 

practicable” (AEC 1973). Additionally, the original design used only coarse mesh traveling 

screens. MPCA issued the NPDES permit No. MN0004006 in 1981, dictating changes to the 

cooling system technology and operation (MPCA 1981). 

Changes to the cooling system technology included the alteration or replacement of the cooling 

water intake structure to minimize entrainment and impingement mortality; the installation of fine 

mesh screens, fish buckets, and a fish return system; and design criteria limiting the screen face 

velocity to 0.5 fps at a discharge rate of 800 cubic fps while the fine mesh screens were in use. 

The applicant completed the modifications to the cooling system by 1983 (NMC 2008). 

Changes to the operation of the cooling system included limits on plant flow and withdrawal 

between April 1 and June 30, after completion of the new cooling water intake structure; the use 

of the fine mesh screens from April 16 to August 31 (although the current permit sets the start 

date as April 1); and the implementation of studies to evaluate the effectiveness of the new 

cooling system (NMC 2008; MPCA 2006). The NPDES permit also specifies the conditions for 

the three different cooling system modes, which will be discussed in Section 4.5.5.

On July 9, 2004, the U.S. Environmental Protection Agency (EPA) published a final rule in the 

Federal Register (69 FR 41575) that addresses cooling water intake structures at existing power 

plants, including PINGP 1 and 2, where flow levels exceed a minimum threshold value of 50 

million gpd. The rule is Phase II in the EPA’s development of CWA 316(b) regulations that 

establish national requirements applicable to the location, design, construction, and capacity of 

cooling water intake structures at existing facilities that exceed the threshold values for water 

withdrawals. The national requirements, which were to be implemented through the NPDES 

permitting process, minimize the adverse environmental impacts associated with the continued 

use of the intake systems.

Under the Phase II rule, licensees would have been required to demonstrate compliance with 

the Phase II performance standards at the time of renewal of the NPDES permit. As part of the 

NPDES renewal, licensees may have been required to alter the intake structure, redesign the 

cooling system, modify station operation, or take other mitigative measures to comply with this 

regulation. The new performance standards were designed to significantly reduce impingement 

mortality and entrainment due to water withdrawals associated with cooling water intake 

structures used for power production. Any additional site-specific mitigation required as a result 

of the 316(b) Phase II reviews would result in less impact from impingement and entrainment 

during the license renewal period.

Effective July 9, 2007, the EPA suspended the Phase II rule (72 FR 37109). As a result, all 

permits for Phase II facilities should include conditions under Section 316(b) of the CWA that 

are developed on a Best Professional Judgment basis, rather than best technology available. 
Environmental Impacts of Operation

4-7

Best Professional Judgment is used by the NPDES permit writers to develop technology-based 

permit conditions on a case-by-case basis using all reasonably available and relevant data. Any 

site-specific mitigation required under the NPDES permitting process would result in a reduction 

in the impacts of continued plant operations.

When the current NPDES permit was issued in 2006, the 316(b) Phase II rule was still in effect, 

and the permit required Northern States Power Co. (NSP) to submit documents including a 

comprehensive demonstration study to characterize entrainment and impingement mortality and 

show that the changes to technology and operation of the cooling system satisfied the 

performance standards of the Phase II rule. NSP submitted the required documents on time; 

however, as described above, the Phase II rule was suspended in 2007 before MPCA issued a 

316(b) determination for PINGP 1 and 2. At the time this SEIS was published, EPA had not put 

in place new regulations, and until it does, it is unlikely that MPCA will review the submitted 

documents. PINGP 1 and 2 will continue to operate under the existing 2006 NPDES permit, 

unless otherwise directed by the State of Minnesota.

Baseline monitoring for impingement was conducted three days a week from 1973 through 1980 

at PINGP 1 and 2; from 1981 through 1984, the samples were taken three days every other 

week. Samples were taken by emptying the trash baskets, separating out debris, and counted 

based on taxonomy. Both living and dead organisms were included in the impingement totals, 

and counts were doubled for years 1981 to 1984 to account for the biweekly collection (Table 4-

6). Based on the table presented in the Impingement Mortality and Entrainment Characterization 

Study (Xcel Energy Environmental Services 2006), the total annual impingement at PINGP 1 

and 2 during the years before the changes to equipment and operation took effect ranged from 

approximately 24,967 fish (in 1979) to 554,590 fish (in 1977); the average impingement over 

those 12 years was 164,629 fish per year. Gizzard shad had the highest impingement, 

comprising an average of about 80 percent of the total number impinged (Xcel Energy 

Environmental Services 2006). Neither the original 316(b) demonstration (NUS 1976) nor the 

Impingement Mortality and Entrainment Characterization Study (Xcel Energy Environmental 

Services 2006) provide the mortality rates from these baseline studies, except to note that live 

impinged organisms were counted and returned to the river.
Environmental Impacts of Operation

4-8

Table 4-6. Estimated Number of Fish Impinged at PINGP 1 and 2, 1973-1984

Year Total Number Gizzard Shad Percent Gizzard Shad

1973 69,226 65,000 93.90

1974 146,063 136,667 93.57

1975 93,324 70,506 75.55

1976 261,295 152,878 58.51

1977 554,590 456,949 82.39

1978 105,983 93,895 88.59

1979 24,967 9,381 37.57

1980 110,764 97,840 88.33

1981 54,376 47,966 88.21

1982 121,896 67,338 55.24

1983 222,478 171,972 77.30

1984 210,590 203,956 96.85

TOTAL 1,975,552 1,574,348 79.69

Source: Adapted from Xcel Energy Environmental Services 2006

The baseline studies for entrainment were conducted in 1974 and 1975. Abundance was 

estimated for larval fish and eggs in the vicinity of Prairie Island, although the individual species 

were not identified. NUS Corporation conducted entrainment monitoring in 1975 from May into 

September and estimated that PINGP 1 and 2 entrained 8,371,000 fish eggs and 61,645,00 

larval and juvenile fish were entrained during the sample period (NUS 1976). The authors of the 

study concluded that the entrainment of these eggs and larvae represented a loss of 2,830,000 

adult fish, an overwhelming percentage of which were forage fish. (Xcel Energy Environmental 

Services 2006)

The new screenhouse was installed in 1983 and, in the spring of 1984, the fine-mesh screens 

were placed into operation. Because of the finer mesh, the eggs, larvae, small juveniles, and 

even some smaller adults, which in previous years would have been entrained, were now 

impinged on the screens, washed into the fish return system, and discharged into the river. 

Increased impingement meant that entrainment rates were dramatically reduced. In 1984, 

samples were taken from the back wash of the fine-mesh screens and compared to the 

impingement samples. The Impingement Mortality and Entrainment Characterization Study 

found that, based on this data, the front spray wash was over 98 percent effective in minimizing 

entrainment (Xcel Energy Environmental Services 2006). However, this reduction in entrainment 

translates to a dramatic increase in impingement, as described below.

The impingement verification study was conducted by sampling the impingement on the finemesh screens from 1984 through 1988, April through August. A quarter of the screen wash 

water was diverted into collection tanks in the environmental lab to assess the number 

impinged, determine taxonomy and age of impinged fish, and monitor initial and latent survival. 

Based on the data from the verification studies, estimates for the weekly and annual number of 

impinged organisms were extrapolated. In 1984, the estimated impingement during the months 

April through August was 492.8 million organisms. However, the group responsible for the 1984 

sampling hypothesized that this was a gross overestimate of impingement, due to a sampling 
Environmental Impacts of Operation

4-9

equipment design – the pipe from the screenhouse was not flushed before samples were taken, 

allowing any organisms in the pipe prior to sampling to be included in the counts. This meant 

that the sample counts included organisms that were not entrained during the sampling time 

period, and when these counts were extrapolated to daily totals, the estimate was unrealistically 

high (NSP 1985). Therefore, the sampling equipment was redesigned in 1985. The following 

years showed a 10-fold decrease in the estimated impingement levels: 42.5 million (1985), 62.7 

million (1986), 77.1 million (1987), and 67.2 million (1988). The estimated impingement during 

the months April though August of 1984 through 1988, based on the verification studies, is 

presented in Table 4-7 and is broken down into life stages. (Xcel Energy Environmental 

Services 2006)

The average of the estimated number of eggs impinged during the spring and summer months 

when the fine mesh screens were in place, excluding data from 1984, was about 12.5 million, 

and the average level of impingement for larvae (prolarvae and postlarvae combined) per year 

was approximately 46 million. In the 1975 baseline study for entrainment, NUS estimated just 

over 8 million eggs and 61.5 million larvae were entrained. Annual fluctuations in impingement 

levels, as shown in Tables 4-6 and 4-7, suggest that the difference between the baseline and 

verification studies could be due to annual changes in the number of eggs and larvae present in 

the river, and in fact, more eggs were impinged on average during the verification studies than 

had been entrained during the baseline study.

Numbers of adults impinged by the fine mesh screens are far lower than the total number of fish 

impinged during the baseline studies, although from the data, the NRC staff could not determine 

what percentage of the baseline impinged fish were adults, as some juveniles would have been 

impinged as well. Likewise, staff found it difficult to compare the numbers of impinged juveniles 

from the verification studies to the impingement totals from the baseline studies. However, staff 

assumed that many juveniles that had head-on dimensions smaller than 3/8 in. would have 

been entrained prior to the installation of fine mesh screens.

For the impingement mortality and entrainment characterization study, Xcel Energy 

Environmental Services (2006) calculated the survivorship of the impinged fish using only the 

juvenile or larger fish that would have been impinged on the coarse mesh screens. The total 

survivorship based on the study years 1984 through 1988 was 71.5 percent. When adjusted to 

account for sampling-induced mortality, Xcel Energy Environmental Services calculated that the 

survivorship rises to 80 percent. The original intake structure had no fish return system, only 

trash baskets, and therefore impingement survivorship can be assumed to have been zero, 

although the characterization study does note that organisms that were alive when collected for 

impingement monitoring were released to the river.
Environmental Impacts of Operation

4-10

Table 4-7. Estimated Number and Percent Composition of Fish Life Stages Impinged on Fine Mesh Sc

through August, 1984-1988

1984 1985 1986 1987 

Life Stage Number Percent in 

year

Number Percent 

in year Number Percent 

in year Number Percent 

in year

eggs 11,882,792 2.41 17,534,761 41.27 6,504,222 10.36 14,271,422 18.50 

prolarvae 100,116,592 20.32 16,405,893 38.61 40,908,477 65.19 31,886,239 41.33 

postlarvae 17,311,818 3.51 5,326,535 12.54 13,283,595 21.17 28,844,661 37.39 

juveniles 363,039,236 73.67 3,096,336 7.29 1,963,864 3.13 2,125,830 2.76 

adults 396,573 0.08 2,688 0.01 8,848 0.01 16,548 0.02 

unidentified 71,624 0.01 120,816 0.28 84,045 0.13 0.00 0.00 

TOTAL 492,818,635(a) 100.00 42,487,029 100.00 62,753,051 100.00 77,144,700 100.00 

(a)Data from 1984 was an overestimate due to sampling equipment design (Xcel Energy Environmental Services 2006).

Source: Adapted from Xcel Energy Environmental Services 2006
Environmental Impacts of Operation

4-11

Based on the changes to PINGP 1 and 2’s cooling system since the mid-1980s, the use of finemesh screens during sensitive times of year, the use of closed- and helper-cycle cooling modes, 

and the reduction in flows from April through June, as well as the data presented in the CWA 

Section 316 demonstrations, which show a reduction in impingement mortality and entrainment 

after the installation of new intake structures (NUS Corporation 1976; Xcel Energy 

Environmental Services 2006), the NRC staff determined that the potential impacts of 

impingement and entrainment of fish and shellfish by the PINGP 1 and 2 cooling system during 

the 20-year renewal period would be SMALL. PINGP 1 and 2 currently employ a number of 

mitigation measures, including using closed and helper cycle cooling, fine-mesh screens, and 

flow limitations. Additional mitigative measures that PINGP 1 and 2 could add include operating 

in closed cycle more often, using the fine-mesh screens for a longer period of time, reducing 

intake velocities, and operating under reduced intake flows. The staff did not identify any cost 

benefit studies applicable to these mitigation measures. It is the responsibility of the MPCA to 

impose any restrictions or modifications to the cooling system to reduce the impact of 

entrainment and impingement under the NPDES permitting process.

4.5.3 Heat Shock

The NRC defines heat shock as acute thermal stress caused by exposure to a sudden elevation 

of water temperature that adversely affects the metabolism and behavior of fish and can lead to 

death. At power plants, heat shock is most likely to occur when an offline unit returns to service 

or when a station has a discharge canal that effectively traps heated water in a smaller area 

then would a discharge point directly on a river or lake. For plants with once-through cooling 

systems, the impacts of heat shock are listed as a site specific, or Category 2 issue, and require 

a plant-specific evaluation before license renewal, because of continuing concerns about acute 

thermal-discharge impacts and the possible need to modify thermal discharges in the future in 

response to changing environmental conditions (NRC 1996). PINGP 1 and 2 operate in a 

closed-cycle mode part of the year, during which time heat shock is categorized as a Category 1 

issue. The helper-cycle mode is not discussed in the GEIS (NRC 1996), nor is it classified as 

either a Category 1 or 2 issue. To be conservative, the NRC staff considered heat shock at 

PINGP 1 and 2 as a Category 2 issue and undertook an assessment of heat shock for the entire 

year under all three operating modes. 

To perform this evaluation, the NRC staff reviewed the applicant’s ER (NMC 2008) and related 

documents, including the CWA Section 316 demonstrations (HDR 1978), and visited the PINGP 

1 and 2 site. The NRC staff also reviewed the applicant’s most recent NPDES Permit No. 

MN0004006 issued on June 30, 2006, by the MPCA (MPCA 2006).

Section 316(a) of the CWA establishes a process by which a discharger can demonstrate that 

the established thermal discharge limitations are more stringent than necessary to protect 

balanced, indigenous populations of fish and wildlife and obtain facility-specific thermal 

discharge limits (33 USC 1326). In 1978, Henningson, Durham, and Richardson, Inc., provided 

MPCA with a Section 316(a) demonstration that addressed compliance with the thermal effluent 

limitations of the NPDES permit and environmental impacts of the thermal discharge (HDR 

1978).

For the demonstration, Henningson, Durham, and Richardson, Inc., modeled the thermal plume 

for typical and extreme environmental conditions, including both two- and three-dimensional 

models. In 13 of the 61 cases modeled, the plume exceeded the NPDES thermal limits that had 

been proposed, and 11 of these cases were for “typical” environmental conditions. Therefore, 

the 316(a) demonstration stated that a variance to the proposed NPDES permit would be 

necessary to meet thermal criteria, or else the plant would have to be derated. The suggested 

variance was an extension of the mixing zone boundary from October through March. The 
Environmental Impacts of Operation

4-12

summary conclusion of the 316(a) was that the thermal discharge of PINGP 1 and 2 would not 

“cause appreciable harm to any aquatic biota and the protection and propagation of a balance, 

indigenous biota has been maintained.” (HDR 1978)

In response to the 316(a) demonstration, MPCA issued the NPDES permit in 1981 for PINGP 1 

and 2. The permit stated that PINGP 1 and 2 required a new discharge structure. It also 

specified changes to the operation of PINGP 1 and 2, including that the cooling towers be 

operated to the maximum extent practicable from April 1 to November 30, new thermal limits for 

the spring and summer months and fall and winter months, that the operators of PINGP 1 and 2 

minimize to the extent practicable abrupt temperature changes, and that the river temperature 

below Lock and Dam 3 be monitored continuously. The requirements of the current NPDES 

permit are summarized in Section 2.1.6.3. (NMC 2008)

The new discharge structure was completed in 1983, along with the new intake structure as 

described in Section 4.5.2. The design of the new discharge had several goals: promote mixing 

of discharged and receiving waters, eliminate recirculation of heated discharge into intake, 

minimize cold shock potential, and prevent fish from entering discharge pipes (discharge rate is 

8 to 10 fps) (Stone and Webster 1983).

During the spring and summer months (from April 1 through the fall trigger point, when the daily 

average upstream river temperature falls below 43 °F [6 °C]) the cooling towers are operated so 

that the water temperature below Lock and Dam 3 is not raised more than 5 degrees above 

ambient temperature and does not exceed a daily average of 86 °F (30 °C). During the fall and 

winter months (from the fall trigger point through March 31), the water temperature below Lock 

and Dam 3 cannot exceed 43 °F (6 °C) “for an extended period of time.” (MPCA 2006)

Table 4-8 presents the upper lethal threshold for six common species of fish that occur in the 

vicinity of PINGP 1 and 2. The summer daily average limit of 86 °F (30 °C) imposed by the 

NPDES permit is protective of these species of fish, and is based on the fisheries data 

available. The MPCA has updated the thermal limits in past NPDES permits to account for 

changes in fishery data, and NRC assumes that MPCA will continue to apply the best 

information available to future NPDES permits,

Table 4-8. Upper Lethal Thresholds of Common Fish Species Occurring in the 

Vicinity of PINGP 1 and 2

Species Upper Lethal Threshold Life Stage

Walleye (Stizostedion vitreus) 31.6 °C (88.8 °F) Juvenile

Channel catfish (Ictalurus punctatus) 38.3 °C (100.9 °F)

33.5 °C (92.3 °F)

Juvenile

Adult

Northern pike (Esox lucius) 33.3 °C (91.9 °F) Juvenile

Gizzard shad (Dorosoma cepedianum) 36.5 °C (97.7 °F) Juvenile

Carp (Cyprinidae) 41 °C (105.8 °F)

36 °C (96.8 °F)

Juvenile

Adult

Black crappie (Pomoxis nigromaculatus) 33 °C (91.4 °F) Juvenile

Source: Adapted from HDR 1978

Based on the applicant’s ER (NMC 2008), the current NPDES permit (MPCA 2006), and the 

316(a) demonstration (HDR 1978), the NRC staff determined that heat shock at PINGP 1 and 2 
Environmental Impacts of Operation

4-13

during the 20-year renewal period is unlikely because of the design and operation of the PINGP 

1 and 2 cooling system. Therefore, the NRC staff concludes that the potential impact to fish and 

shellfish due to heat shock during the renewal term is SMALL. PINGP 1 and 2 currently employ 

a number of mitigation measures, including using closed and helper cycle cooling and flow 

limitations. Additional mitigative measures that PINGP 1 and 2 could add include operating in 

closed cycle more often and operating under reduced intake flows. The staff did not identify any 

cost benefit studies applicable to these mitigation measures. It is the responsibility of the MPCA 

to impose any restrictions or modifications to the cooling system to reduce the impact of heat 

shock under the NPDES permitting process.

4.5.4 Total Impacts on Aquatic Resources

Impingement, entrainment and heat shock all act on the same populations of aquatic resources. 

The purpose of this section is to provide perspective on the total impact of cooling system 

operation on fish and other aquatic resources. The MPCA, not the NRC, is responsible for 

issuing and enforcing NPDES permits. NRC assumes that MPCA will continue to apply the best 

information available to future NPDES permits. Because the NRC level of impact associated 

with impingement and entrainment is small and the level of impact associated with thermal 

impacts is small, NRC staff believes that the total impact from all of these sources together on 

aquatic resources would also be SMALL through the period of license renewal. 

4.6 Terrestrial Resources

The issues related to terrestrial resources applicable to PINGP 1 and 2 are listed in Table 4-9. 

There are no Category 2 issues related to terrestrial resources. 

Table 4-9. Terrestrial Resources Issues. Section 2.2.6 provides a description of the 

terrestrial resources at PINGP 1 and 2 and in the surrounding area.

Issues GEIS Section Category

Cooling tower impacts on crops and ornamental vegetation 4.3.4 1

Cooling town impacts on native plants 4.3.5.1 1

Bird collisions with cooling towers 4.3.5.2 1

Power line right-of-way management (cutting herbicide 

application) 4.5.6.1 1

Bird collisions with power lines 4.5.6.1 1

Impacts of electromagnetic fields on flora and fauna (plants, 

agricultural crops, honeybees, wildlife, livestock) 4.5.6.3 1

Floodplains and wetland on power line right-of-way 4.5.7 1

Regarding bird collisions with power lines, the GEIS (NRC 1996) notes that “no relatively high 

collision mortality is known to occur along transmission lines associated with nuclear power 

plants in the United States other than the Prairie Island plant in Minnesota.” The GEIS also 

notes that PINGP 1 and 2 may be the only nuclear facility for which surveys have been 

completed to determine the number and composition of birds that collide with offsite lines. 

Goddard (1977; 1978; 1979) conducted a 5-year survey of Xcel-owned transmission lines at 

PINGP 1 and 2. Data was gathered by walking several transmission line right-of-way (ROW) 

transects on a weekly basis from April 22 through May 27 of 1974 through 1978. The transects 
Environmental Impacts of Operation

4-14

spanned from the substation just north of PINGP 1 and 2 to transmission line towers nearest the 

Vermillion River along a portion of transmission lines that run perpendicular to the Mississippi 

Flyway. A total of 453 birds were found over the entire 5-year period of observation, and most 

collisions were found to occur during inclement weather (Goddard 1979). The study found that a 

greater number of collisions occurred on transects that were perpendicular to flyways; however, 

transmission lines only resulted in greater collisions for a few species. The majority of bird 

carcasses identified were mourning doves, starlings, red-winged blackbirds, common grackle, 

brown-headed cowbirds, ring-necked pheasants, American coots, and sora rails; no raptors 

were found (Goddard 1979). No further formalized studies have been conducted on or near the 

PINGP 1 and 2 site.

PINGP 1 and 2 associated transmission lines have marking devices on lines near waterways 

and certain areas with a known history of avian collision. These marking devices are staggered 

to divert bird flight paths and minimize the risk of collision with transmission lines. In a study 

conducted in Lower Crab Creek, Washington, and Bybee Lake in Portland, Oregon, Beaulaurier 

(1981) found that transmission line marking reduced collision mortality about as effectively as 

groundwire removal where comparisons were possible. Effectiveness of reducing collisions for 

certain species may vary by type and color of marking device, though marking devices, in 

general, reduce bird collision rates when compared to unmarked portions of transmission lines 

(Janss and Ferrer 1998).

In 2002, Xcel Energy voluntarily entered into a Memorandum of Understanding (MOU) with the 

U.S. Fish and Wildlife Service (FWS) in order to ensure the company’s compliance with the 

Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act (USDOJ 2002). The 

MOU covers Xcel Energy transmission lines in 12 U.S. states. As a result of the MOU, Xcel 

Energy is in the process of creating Avian Protection Plans (APPs) for each of these 12 states. 

Xcel Energy completed a draft APP for Minnesota which was submitted to FWS at the end of 

the 2008 calendar year. The APP was approved by FWS in February of 2010. The APP is valid 

indefinitely and will be updated on an “as needed” basis. As part of the APP, Xcel Energy has 

developed guidelines to standardize avian protection across all of the company’s operating 

divisions (which include all its transmission lines, not just those associated with the operation of 

PINGP). Those lines that have been identified as having the highest risk of migratory bird 

electrocution and collision will be retrofitted or modified to decrease the risk to migratory birds 

on a schedule that corresponds with regular transmission line maintenance starting in 2010 and 

ending in 2014. (NSP 2010).

The MOU also requires semi-annual reports of avian injury and mortality along Xcel Energy 

transmission lines, which are submitted to FWS in January and July of each year. Since these 

reports began in 2002, two transmission line-related incidents have been reported at PINGP 1 

and 2. The first incident was about a cormorant that was found dead near the PINGP 1 and 2 

substation in October of 2002, and the second was about a dead pelican which NSP personnel 

found off-site near the Spring Creek transmission line in April 2008. Xcel Energy provides 

training to its staff members that maintain transmission line ROWs to ensure that the conditions 

of the MOU are met. Additionally, Xcel Energy established company-wide Avian Protection 

Standards in 2006.

The NRC did not identify any new and significant information during the review of the applicant’s 

ER (NMC 2008), the staff’s site audit, the scoping process, or the evaluation of other available 

information. Therefore, there are no impacts related to these issues beyond those discussed in 

the GEIS. For these issues, the GEIS concluded that the impacts are SMALL, and additional 

site-specific mitigation measures are not likely to be sufficiently beneficial to warrant 

implementation.
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4-15

4.7 Threatened or Endangered Species

This site-specific, or Category 2 issue requires consultation with the appropriate agencies to 

determine whether threatened or endangered species are present and whether they would be 

adversely affected by continued operation of PINGP 1 and 2 during the license renewal term. 

The characteristics and habitats of threatened and endangered species in the vicinity of the 

PINGP 1 and 2 site are discussed in Sections 2.2.6 and 2.2.7 of this SEIS.

Table 4-10. Threatened or Endangered Species. Section 2.2.7 describes the 

threatened or endangered species on or near PINGP 1 and 2.

Issue GEIS Section Category

Threatened or endangered species 4.1 2

The NRC contacted the FWS on July 22, 2008, regarding threatened and endangered species 

at the PINGP 1 and 2 site (NRC 2008b). A description of the site and the in-scope transmission 

lines and a preliminary assessment of the Federal threatened, endangered, and candidate 

species potentially occurring on or near the PINGP 1 and 2 site was provided in this letter. In 

response, on August 13, 2008, the FWS indicated that the Higgins eye pearlymussel (Lampsilis 

higginsii) is present in Upper Mississippi River within the vicinity of PINGP 1 and 2, though no 

designated critical habitat is present for the species in Goodhue County (FWS 2008). No 

terrestrial Federally listed species were included in the letter.

Although the NRC does not believe that license renewal would adversely affect the Federally 

listed species, the Higgins eye pearlymussel, the NRC has prepared a Biological Assessment 

for FWS, as part of the Section 7 consultation under the Endangered Species Act of 1973 

(ESA), to document its review. This biological assessment is provided in Appendix D of this 

SEIS.

The NRC contacted the MNDNR on July 22, 2008, to request data from the Minnesota Natural 

Heritage Information System in order to determine which State-listed species may be affected 

by continued operations and maintenance procedures at the PINGP 1 and 2 site and associated 

transmission line ROWs (NRC 2008a). The MNDNR provided natural heritage data in the 

vicinity of PINGP 1 and 2 in their response to the NRC staff dated August 26, 2008 (MNDNR 

2008a).

4.7.1 Aquatic Species

As described in Section 2.2.7, two Federally-listed endangered species and two candidate 

species for Federal listing are known to exist within Goodhue County or within Dakota, Scott, 

and/or Washington Counties, through which the in-scope transmission lines traverse. The 

winged mapleleaf (Quadrula fragosa) is listed as endangered, and the spectaclecase 

(Cumberlandia monodonta) and the sheepnose (Plethobasus cyphyus) are both candidates for 

Federal listing; however, these three mussels are not known to be present in the vicinity of the 

PINGP 1 and 2 site or within the transmission line ROWs and will, therefore, not be discussed 

further in this section. Five State-listed mussel species are known to occur within Pool 3 of the 

Mississippi River: the rock pocketbook (Arcidens confragosus), the black sandshell (Ligumia 

recta), the washboard (Megolonaias nervosa), the hickory nut (Obovaria olivaria), and the 

wartyback (Quadrula nodulata).
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4-16

The Higgins eye pearlymussel (Lampsilis higginsii) is the only Federally listed species that 

occurs within the vicinity of the PINGP 1 and 2 site. As described in Section 2.2.6, State and 

Federal agencies, including the FWS, determined that an area within Pool 3, which is located

0.5 mi (0.8 km) upstream of the PINGP 1 and 2 intake structure, was a suitable habitat for a 

subadult Higgins eye relocation project. In 2002, the U.S. Army Corps of Engineers (USACE), in 

cooperation with the Mussel Coordination Team, prepared an environmental assessment for the 

relocation plan for the Higgins eye, in which they report “good recovery of mussels” following the 

relocation of 100 adult Higgins eye by MNDNR, WDNR, and the FWS (USACE 2002). The 

environmental assessment also states that the location was identified as a good relocation site 

based on the 2000 Minnesota 305(b) water quality status report, which listed Pool 3 as having 

“full support” for aquatic life (USACE 2002). As of a 2005 status report, over 4000 sub-adults 

have been relocated to the Sturgeon Lake section of Pool 3 (Mussel Coordination Team 2005). 

The Mussel Coordination Team (2005) reported “good recovery” for Pool 3 subadults after 

conducting monitoring in 2003.

Higgens Eye Pearlymussel

The cooling water intake structure of a power plant can pose a threat to aquatic species 

because fish and shellfish have the potential to be impinged on screens or entrained by the 

cooling system. However, the life cycle of the Higgins eye pearly mussel makes it unlikely that 

individuals of this species would be at risk of impingement or entrainment. 

Fertilized Higgins eye eggs are carried by a gravid female until they mature into glochidia, a 

microscopic larval stage of large freshwater mussel species. The female uses a lure to attract 

host fish and then releases the glochidia into the water column, where they can attach to the 

gills of the fish. If they fail to attach to the host, they have a low likelihood of attaching later, and 

will, therefore, not mature into juveniles. Once attached to the host fish’s gills, the glochidia 

mature into juveniles and then drop to the river bottom where they settle. Once settled on 

suitable substrate, the juveniles are sessile until maturation to adulthood. Because juveniles are 

not present in the water column, the likelihood of entrainment during this life stage is very low.

The larval stage of the Higgins eye life cycle is the most likely to be affected by the cooling 

system. Because glochidium attach to a host fish, if the host fish is impinged and killed on the 

screens of the cooling system, the glochidium would be unlikely to be able to mature into a 

juvenile. If the glochidium had reached maturity and dropped off the fish while the fish was 

impinged, it would be swept into the cooling system and would be entrained.

Suitable fish hosts for Higgins eye glochidia include freshwater drum (Aplodinotus grunniens), 

largemouth bass (Micropterus salmoides), smallmouth bass (Micropterus dolomieu), yellow 

perch (Perca falvescens), sauger (Stizostedion canadense), walleye (Stizostedion vitreum 

vitreum), and black crappie (Pomoxis migromaculatus); marginal fish hosts include northern 

pike (Esox lucius), bluegill (Lepomis macrochirus), and green sunfish (Lepomis cyanellus) (FWS 

2004).

Historic data collected from 1973 through 1984 (Table 4-10a) indicate that all seven of Higgins 

eye host species have been impinged within the cooling system at PINGP 1 and 2 in relatively 

small numbers. The PINGP 1 and 2 screenhouse was redesigned in 1983 to further reduce the 

number of fish impinged and increase the likelihood of survival of those individuals that were 

impinged (Xcel Energy Environmental Services 2006). Between April and August of 1984 

through 1988, Xcel Energy conducted a 316(b) demonstration study. Impingement levels for 

this study were recorded by family rather than by species; therefore, the specific rates of 

impingement for the seven Higgins eye host species are unavailable during this time period. 

However, impingement rates by family indicate that impingement of each of the seven Higgins 

eye host species remained low during this time period. Freshwater drum, which are in the 
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4-17

Sciaedae family, were not identified among the adults impinged during the 316(b) demonstration 

study. Largemouth bass, smallmouth bass, bluebill, and green sunfish are members of the 

Centrarchidae family. The 316(b) demonstration indicated that an estimated 672 adults from this 

family were impinged in 1987, which comprised less than 0.01 percent of the total impinged and 

indicated a very low probability of adults of this family being impinged by the PINGP 1 and 2 

cooling system. Yellow perch, sauger, and walleye are all members of the Percidae family. In 

1984, an estimated 43,680 adults were impinged, and in 1987, an estimated 1,176 adults were 

impinged. NSP believes that the impingement estimates in 1984 were a gross overestimate 

due to the design of the sampling equipment. The sampling equipment was redesigned in 1985 

to more accurately capture impingement data at PINGP 1 and 2. NSP has stated that the 1987 

data reflect a more accurate estimate of impingement as a result of the redesigned sampling 

equipment (NSP 2010). The number of Percidae impinged in 1987 also comprises less than 

0.01 percent of the total individuals impinged and indicates a low probability of adults from the 

Percidae family being impinged by the PINGP 1 and 2 cooling system. (Xcel Energy 

Environmental Services 2006).

The total population of each host species in Pool 3 as well as the likelihood that impinged host 

species have Higgins eye glochidium attached to them is uncertain, but the overall low 

probability of Higgins eye host species to be impinged in the PINGP 1 and 2 cooling system 

indicates that impingement of host species is not likely to noticeably affect the Higgins eye 

population.

Table 4-10a. Estimated Impingement of Higgins eye Host Species, 1973 to 1984

Scientific Name Common Name Total Estimated 

Number Impinged

Percent of Total Fish 

Impinged(a)

1973 to 1984

Aplodinotus grunniens freshwater drum 227,549 11.52

Micropterus dolomieu smallmouth bass 87 0.00

Micropterus salmoides largemouth bass 31 0.00

Percafal vescens yellow perch 276 0.01

Pomoxis spp.(b) crappie 23,346 1.18

Stizostedion canadense sauger 548 0.03

Stizostedion vitreum vitreum walleye 425 0.02

(a)Between 1973 and 1984, an estimated 1,975,552 individuals comprised of 61 taxa were impinged. (b)The genus Pomoxis is comprised of the black crappie and white crappie. The black crappie is a host 

species for the Higgins eye, while the white crappie is not. However, the study recorded impingement 

data for the genus as a whole and did not identify levels of impingement for the individual species.

Source: Xcel Energy Environmental Services 2006

In order to assess the potential impact to the Higgins eye pearlymussel, the NRC staff 

considered the life cycle of the Higgins eye, the limited time the mussel spends in the water 

column during which it could be subject to entrainment, and the low probability of the primary 

fish hosts being impinged. In addition, the NRC recognizes that the FWS determined that the 

area just upstream of the PINGP 1 and 2 intake structure was a suitable site for the Higgins eye 

relocation project. Therefore, the NRC staff concludes that the species is unlikely to be 

adversely affected during the renewal period. If the Higgins eye relocation project is successful 

in establishing a reproducing population during the renewal term of the licenses and if

impingement and entrainment at PINGP 1 and 2 of suitable fish hosts would appear to 

adversely affect that mussel population, NRC might have to re-assess the potential for adverse 

effects in the future. Attached to this SEIS is the biological assessment performed by the NRC

for the review of the FWS.
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State-listed Mussels

As described in Section 2.2.7.1, five State-listed mussel species are known to occur within 

Pool 3 of the Mississippi River: the rock pocketbook, the black sandshell, the washboard, the 

hickory nut, and the wartyback. These species are not likely to be disturbed during regular 

maintenance activities within the Mississippi River, but would likely be disturbed during any 

major dredging activities associated with the continued operation of PINGP 1 and 2 for an 

additional 20 years. Four of these species (all but the wartyback) are considered rare, which 

means that the species does not usually appear in sample collections, that populations are 

either naturally small or have declined, and that the population may or may not be near 

extirpation (Ecological Specialists 2009).

In April 2010, NSP undertook a larger-scale dredging project, which included dredging of the 

main discharge canal and the intake channel (discussed in more detail in Section 2.1.7.4). NSP 

submitted a Unionid Survey (Ecological Specialists 2009) to the MNDNR to determine if any 

impacts to State-listed mussel species would occur as a result of the dredging activities. The 

survey identified the five State-listed mussels listed above as occurring in Pool 3 in the vicinity 

of PINGP 1 and 2, none of which had been collected in the vicinity of PINGP during a previous 

mussel survey conducted in 1980 (Xcel Energy Environmental Services 2006). During the 2009 

survey, approximately 900 live mussels, 2.1 percent of which were State-listed, were removed 

and relocated to an area of Pool 3 that would not be affected by the proposed dredging; 

however, the survey concluded that it was likely that more mussels were scattered throughout 

the area, some of which may be State-listed species (Ecological Specialists 2009). The survey 

did not identify the presence of the Federally-listed Higgins eye within the area of Pool 3 that 

would be dredged. Overall, the survey concluded that the poor habitat quality and dominance of 

common (non-State-listed) mussel species suggested that long term impacts to the mussel 

community would not occur as a result of the proposed dredging (Ecological Specialists 2009). 

In October 2009, MNDNR (2009) determined that because the dredging project would be 

unable to avoid the taking of State-listed mussel species, NSP must obtain a special permit per 

Minnesota’s Endangered Species Statute (M.S., Sect. 84.0895 and associated Minn. Rules, 

Parts 6212.1800-2100), which prohibits the taking of State-listed threatened or endangered 

species without a permit from MNDNR. MNDNR estimated that the dredging project would take 

2,603 State-endangered and 473 State-threatened mussels based on extrapolations from the 

2009 mussel survey (MNDNR 2009). Because the dredging project could not avoid the take of 

State-listed mussels, NSP obtained a special permit to take State-listed mussels on March 1, 

2010, with the condition of NSP providing compensatory mitigation to the MNDNR for the 

“purposes of funding research, propagation, restoration, and/or management activities 

contributing to the recovery and eventual delisting of endangered and threatened mussel 

species within the Mississippi River in Minnesota.” (MNDNR 2010).

Because the maximum age of freshwater mussels is about 50 years, the minimum time that the 

mussel population can be expected to fully replace its pre-dredging population and age 

structure can generally be assumed to be at least 50 years given that dredging activities would 

affect all age classes equally; some individuals that would be destroyed would be near the 

maximum age; and that, typically, age class distributions of freshwater mussels are skewed 

toward older individuals. However, Kelner and Davis (2002) conducted a mussel survey for the 

National Park Service in 2000-2001 and reported that within Pool 3 of the Mississippi River, the 

mussel population is relatively young, and about 68 percent of individuals are less than 11 years 

old. The younger age class structure in this stretch of the Mississippi River was attributed to 

poorer habitat quality compared with neighboring stretches of the river (Kelner and Davis 2002). 
Environmental Impacts of Operation

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Table 4-10b provides a summary of the age class distribution by species for the entire survey, 

which consisted of 152 sample sites along the entire length of the Mississippi National River and 

Recreation Area Corridor, which extends from Dayton, MN through Minneapolis/St. Paul and 

down to Hastings, MN. Table 4-10c provides the average, minimum, and maximum age 

collected during the 2000-2001 survey for the black sandshell, washboard, and wartyback in 

Pool 2, which is directly upstream of Pool 3. The survey did not provide this data for Pool 3, but 

Pool 2 and Pool 3 were recorded to have similar species composition and richness; therefore, 

for purposes of this analysis, Pool 3 is expected to have similar age structure.

Table 4-10b. Mussel Species Age Class Distribution Along the Mississippi National River 

and Recreation Area Corridor, 2000-2001

Scientific Name Common Name Percent (%) of 

individuals 1-5 

years of age(a)

Percent (%) of 

individuals 6-10 

years of age(a)

Percent (%) of 

individuals >10 

years of age(a)

Arcidens confragosus rock pocketbook 80 15 5

Ligumia recta black sandshell 10 60 30

Megolonaias nervosa washboard 0 0 100

Obovaria olivaria hickory nut 50 30 20

Quadrula nodulata wartyback 45 50 5

(a)Percentages are estimated based on Figure 3-1 in the Final Report: Mussel (Bivalvia: Unionidae) 

Survey of the Mississippi National River and Recreation Area Corridor, 2000-01.

Source: Kelner and Davis 2002

Table 4-10c. Mussel Species Average, Minimum, and Maximum Ages within Pool 2 of the 

Mississippi River, 2000-2001

Scientific Name Common 

Name

Number 

Collected

Average Age Minimum Age Maximum 

Age

Ligumia recta black sandshell 7 7.3 5 11

Megolonaias nervosa washboard 1 28.0 28 28

Quadrula nodulata wartyback 9 6.3 2 13

Source: Kelner and Davis 2002

From the data presented in Tables 4-10b and 4-10c, the washboard population is expected to 

take the longest to recover from a population reduction because all individuals collected during 

the 2000-2001 survey were over 10 years of age with a maximum age of 28. The black 

sandshell and wartyback populations are composed of 70 percent and 80 percent of individuals 

below ten years of age, respectively. These two species can be expected to recover at a similar 

rate as the average mussel population in Pool 3, in which 68 percent of individuals are less than 

11 years old. The wartyback and rock pocketbook populations can be expected to recover the 

most quickly after a population reduction because 95 percent of the wartyback population is 

below 10 years of age, and 80 percent of the rock pocketbook population is 1 to 5 years of age.

If NSP undertakes another large-scale dredging project during the proposed license renewal 

term, impacts to State-listed mussel species can be expected to be similar to those described 

above for the April 2010 dredging project. Future dredging would only disturb mussel habitat for 

a short period of time, and some recruitment, and subsequent reproduction, of individuals from 

adjacent unaffected areas of Pool 3 would be expected to replace a portion of the population 

lost to dredging. However, because the State-listed mussel population is not likely to have fully 

recovered from the April 2010 dredging when any future dredging project is undertaken, any 
Environmental Impacts of Operation

4-20

future dredging would be expected to further reduce the mussel population in Pool 3. The 

washboard population would be expected to be the most impacted by a population reduction, 

which may take up to 28 years to replace its age class structure, followed by the black sandshell 

and wartyback populations, which may take approximately 11 and 13 years, respectively, to 

replace their age class structure based on maximum age data from the Kelner and Davis (2002) 

mussel survey. If dredging occurs more than 5 years after the April 2010 dredging, the rock 

pocketbook would be expected to have nearly fully recovered because 80 percent of its 

population was between 1 and 5 years of age in the Kelner and Davis (2002) mussel survey. 

However, given that four of the five State-listed mussel species are considered to be rare (all 

but the wartyback), a further decline in the population would further reduce the number of 

reproducing individuals and could lead to local extirpation. 

Overall, State-listed mussel populations would be expected to noticeably decrease during future 

dredging activities, and the washboard population would be the most likely to be adversely 

affected due to its more mature age class structure. Because population estimates within 

Pool 3 are unavailable, it is uncertain whether population declines as a result of dredging 

activities during the proposed license renewal term would destabilize populations of one or more 

of the State-listed mussel species in the long term. 

Before NSP could undertake a dredging project during the proposed license renewal term, NSP 

would be required to consult with MNDNR and FWS, as required by the Minnesota Endangered 

Species Statute, to determine the likelihood that dredging activities would affect any Federallyor State-listed species. Project modifications, alternatives, and mitigation would be determined 

at that time, and NSP would be required to obtain a special permit per Minnesota’s Endangered 

Species Statute if it is determined by the MNDNR that the project is likely to adversely affect any 

State-listed species.

Conclusion

The NRC staff reviewed information from the applicant's ER (NMC 2008), the staffs site audit, 

the scoping process, various reports from Federal and State agencies, and independent 

studies. The NRC staff concludes that the continued operation of PINGP 1 and 2 during the 

license renewal term is not likely to adversely affect any Federally-listed aquatic species. The 

NRC staff concludes that the continued operation of PINGP 1 and 2 during the license renewal 

term is likely to affect State-listed mussel species and could cause long-term destabilization to 

certain mussel populations. Thus, the staff concludes that the overall impact on threatened or 

endangered aquatic species from an additional 20 years of operation would vary from species to 

species, but overall, would be MODERATE.

The NRC staff did not identify any mitigation measures except those discussed in Section 4.5.2, 

which include operating in closed cycle more often, using the fine-mesh screens for a longer 

period of time, and operating under reduced intake flows, each of which could potentially reduce 

the overall impacts of entrainment and impingement on all species of fish and shellfish. The staff 

did not identify any cost benefit studies applicable to these mitigation measures. The FWS could 

issues a Biological Opinion (BO) for the Higgins eye pearlymussel in response to the NRC 

staff’s Biological Assessment. The FWS evaluates whether there are reasonable and prudent 

measures to further minimize the impact of the PINGP 1 and 2 cooling system on the Higgins 

eye, and these measures would be specified in the terms and conditions of the BO.
Environmental Impacts of Operation

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4.7.2 Terrestrial Species

Currently, no Federally listed threatened or endangered terrestrial species are known to occur 

on the PINGP 1 and 2 site or within the in-scope transmission line ROWs. The State-listed 

peregrine falcon (Falco peregrineus) and bald eagle (Haliaeetus leucocephalus) are known to 

nest in the vicinity of the PINGP 1 and 2 site; however, these species are not expected to be 

adversely affected by continued operation of PINGP 1 and 2. Operation of PINGP 1 and 2 and 

its associated transmission lines are not expected to adversely affect any threatened or 

endangered terrestrial species during the license renewal term.

The NRC staff encourages NSP, Xcel Energy, and Great River Energy to report the existence of 

any Federally or State-listed endangered or threatened species within or near the transmission 

line ROWs to the MNDNR and/or FWS if any such species are identified during the renewal 

term. In particular, if any evidence of injury or mortality of migratory birds or threatened or 

endangered species is observed within the corridor during the renewal period, NRC encourages 

NSP, Xcel Energy, and/or Great River Energy to promptly report this to the appropriate wildlife 

management agencies.

The NRC staff concludes that adverse impacts to threatened or endangered terrestrial species 

during the license renewal term would be SMALL.

4.8 Human Health

The human health issues applicable to PINGP 1 and 2 are discussed below and listed in Table 

4-11 for Category 1, Category 2, and uncategorized issues.

Table 4-11. Human Health Issues. Table B-1 of Appendix B to Subpart A of 

10 CFR Part 51 contains more information on these issues.

Issues GEIS Section Category

Microbiological organisms (occupational health) 4.3.6 1

Microbiological organisms (public health, for plants using 

small rivers) 4.3.6 2

Noise 4.3.7 1

Radiation exposures to public (license renewal term) 4.6.1, 4.6.2 1

Occupation radiation exposures (license renewal term) 4.6.3 1

Electromagnetic fields – acute effects (electric shock) 4.5.4.1 2

Electromagnetic fields – chronic effects 4.5.4.2 Uncategorized

4.8.1 Generic Human Health Issues

No new and significant human health information was identified during the review of the 

applicant’s ER (NMC 2008), the site audit, or the scoping process. The following discussions 

focus on the radiological environmental impacts and the dose impacts to the public from the 

operation of PINGP 1 and 2.
Environmental Impacts of Operation

4-22

PINGP 1 and 2 Radiological Environmental Monitoring Program

PINGP 1 and 2 conducts a radiological environmental monitoring program which monitors the 

radiological impacts to the employees, the public, and the environment around the PINGP 1 and 

2 site. The objectives of the REMP are to:

• Measure and evaluate the levels of radiation and radioactive material in 

the environs to assess the radiological impacts, if any, of plant operation 

in the environment.

• Supplement the results of the radiological effluent monitoring program by 

verifying that the measurable concentrations of radioactive material and 

levels of radiation are not higher than expected based on the 

measurement of radioactive effluents and modeling for the applicable 

exposure pathways.

• Demonstrate compliance with the requirements of applicable Federal 

regulatory agencies.

The REMP includes monitoring of the waterborne environment (surface and sediment from 

shoreline); airborne environment (radioiodine and particulates and direct radiation); and 

ingestion pathways (milk, fish, and food products). Direct radiation pathways include radiation 

from buildings and plant structures, airborne material released from the plant, cosmic radiation, 

fallout, and the naturally-occurring radioactive materials in soil, air and water. 

Thermoluminescent dosimeters are used to measure direct radiation. The airborne pathway 

includes measurements of radioiodine and particulates in air samples. The waterborne pathway 

consists of Mississippi River water, drinking water, upstream and downstream collection of fish 

and sediment from the shoreline near the discharge point for liquid radioactive effluents. 

The PINGP 1 and 2 environmental monitoring program was initiated in May 1970 (prior to plant 

operation) to monitor background radiation levels near the plant site. The monitoring program is 

based on the indicator-control concept, which includes collection of samples at both indicator 

locations (nearby, downwind, or downstream) and at control locations (distant, upwind, or 

upstream). NSP compiles the results of the REMP in the Radiological Environmental Monitoring 

Report.

The NRC staff reviewed the PINGP 1 and 2 REMP reports for 2003 through 2007 and the most 

recent report for 2009 (NMC 2004b, 2005b, 2006b, 2007b, 2008b, NSP 2010c) to identify if 

there were any significant impacts to the environment. During 2007 and 2009, NSP reported 

that there were no plant-related activation or fission products detected in airborne particulate or 

radioiodine filters, milk, drinking water, surface water, fish, shoreline sediment samples, or 

grassy or broadleaf vegetation. However, tritium was detected in ground water samples. All 

reported data on the tritium levels measured in the environmental samples were below 

applicable NRC reporting levels and EPA drinking water standards (NMC 2008c, NSP 2010c).

For its 2009 monitoring, NSP reported the following REMP results:

Gamma spectroscopic analysis of quarterly composites of air particulate filters yielded similar 

results for indicator and control locations. Beryllium-7, which is produced continuously in the 

upper atmosphere by cosmic radiation, was detected in all samples, with an average activity of 

0.087 pCi/m3 for all locations. All other gamma-emitting isotopes were below the lower limit of 

detection (LLD) for the analysis.

Airborne Particulates
Environmental Impacts of Operation

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Weekly levels of airborne iodine-131 were below the LLD of 0.03 pCi/m3 in all samples. There 

was no indication of a plant effect.

Airborne Iodine

Iodine-131 results were below the detection limit of 0.5 pCi/L in all samples. Cs-137 results 

were below the LLD level of 5 pCi/L in all samples. No other gamma-emitting isotopes, except 

naturally-occurring potassium-40, were detected in any milk samples. In summary, the milk 

data for 2009 show no radiological effects of the plant operation.

Milk

In drinking water from the City of Red Wing well, tritium activity measured below the LLD level of 

159 pCi/L in all samples. These concentrations are consistent with levels observed from 1994 

through 2008. Gamma spectroscopy indicates the presence of lead and bismuth isotopes, 

which are daughters of the radium decay chain. There is no indication from the 2009 data of 

any effect of plant operation.

Drinking Water

For 2009, no measurable tritium activity was detected in river water composite samples above 

the concentration level of 159 pCi/L. Gamma-emitting isotopes were below the LLD in all 

samples.

River Water

At control well, P-43 (Peterson Farm) and the four indicator wells (P-8, Community Center; P-6,

Well Water

Lock and Dam No. 3; P-9, Plant Well No. 2; and P-24, Suter Farm) no tritium was detected 

above a concentration level of 161 pCi/L. Gamma-emitting isotopes were below detection limits 

in all samples. In summary, well water data for 2009 show no radiological effects of the plant 

operation.

Three samples of broadleaf vegetation, cabbage leaves, were collected in August and analyzed 

for gamma-emitting isotopes, including iodine-131. The I-131 level was below 0.029 pCi/g wet 

weight in all samples. With the exception of naturally-occurring potassium-40, all other 

gamma-emitting isotopes were below their respective detection limits. There was no indication 

of a plant effect.

Crops

Fish were collected in May and September 2009 and analyzed for gamma-emitting isotopes. 

Only naturally-occurring potassium-40 was detected, and there was no significant difference 

between upstream and downstream results. There was no indication of a plant effect.

Fish
Environmental Impacts of Operation

4-24

Aquatic insects (invertebrates) or periphyton were collected in May and September 2009 and 

analyzed for gamma-emitting isotopes. All gamma-emitting isotopes were below detection 

limits. There was no indication of a plant effect.

Aquatic Insects or Periphyton

Upstream, downstream, and downstream recreational area shoreline sediments were sampled 

in May, June and September 2009 and analyzed for gamma-emitting isotopes. The only 

gamma-emitting isotopes detected were naturally-occurring beryllium-7 and potassium-40. 

There was no indication of a plant effect.

Bottom and Shoreline Sediments

In addition to the REMP, PINGP 1 and 2 have a ground water protection program, which was 

established after the detection of tritium in a residential well in the vicinity of PINGP 1 and 2 in 

1989. The program is designed to monitor the onsite environment for indication of leaks from 

plant systems and pipes carrying liquids with radioactive material. The results of the program 

are reported in an appendix to the REMP report entitled “Special Well and Surface Water 

Samples” (NMC 2007c, 2008c, NSP 2010c). Samples are taken from the onsite and offsite 

wells in the vicinity of the site. The applicant reported that since the beginning of this special 

sampling program, a downward trend in the annual tritium level averages have been observed. 

In 2006, results of tritium sampling showed that levels of tritium in well and ground water were at 

or near expected natural background levels, except for one onsite well, which had levels 

fluctuating from 432 picocuries per liter [pCi/L] to 3773 pCi/L, though this range is well below the 

EPA drinking water standard of 20,000 pCi/L (NMC 2007c). In 2007, two additional monitoring 

wells were sampled and sampling frequency was increased. The 2007 results indicate that 

levels of tritium in the well and ground water were at or near expected natural background levels 

(NMC 2008c). Levels of tritium in the onsite well with fluctuating levels in 2006 as well as the 

two additional monitoring wells fluctuated from 390 pCi/L in February to 2258 pCi/L in November 

2007 (NMC 2007c). In the report, the applicant indicated that the elevated tritium levels in the 

three onsite monitoring wells might be due to prior leakage from the PINGP 1 and 2 liquid 

radwaste discharge pipe or as a result of the turbine building sump water discharges into a 

landlocked area. The discharge pipe was lengthened in 1991, so that liquid discharges are 

released near the end of the discharge canal. In 1992, the discharge pipe from the plant to the 

discharge canal was replaced with a double-walled, leak-detectable piping system. Additionally, 

the applicant discontinued the practice of discharging the turbine building sump water to the 

landlocked area. The data for 2009 indicate that the modification has eliminated the suspected 

radioactive effluent flow into the local ground water (NMC 2008c, NSP 2010c).

Ground Water Protection Program

For 2009, NMC reported the following ground water monitoring results:

Results obtained show tritium in well water and ground water samples at or near expected 

natural background levels except the P-10 and MW-8 sample wells and S-6, Old Admin Building 

storm water runoff. The tritium level annual averages have shown a downward trend since the 

special sampling begun in 1989. Except for sample wells P-10 and MW-8 and runoff sample 

S-6, the 2009 sample results are within the range of expected background tritium levels in 

shallow ground water and surface water due to tritium concentrations measured in precipitation. 

The higher level results at the Suter residence and Birch Lake in 1989 were possibly due to 

seepage from the PINGP discharge canal water into the ground water. This is thought to occur 

due to the elevation difference between the Vermillion River and the discharge canal. The Suter 
Environmental Impacts of Operation

4-25

residence is located between the discharge canal and Birch Lake, which connects to the 

Vermillion River. The PINGP discharge canal piping was lengthened during 1991, so that liquid 

discharges from the plant are released near the end of the discharge canal, diffused and 

discharged to the Mississippi River. In 1992, the underground liquid discharge pipe from the 

plant to the discharge canal piping was replaced with a double-walled, leak-detectable piping 

system. This year's sample results continue to indicate that these modifications have eliminated 

the suspected radioactive effluent flow into the local ground water.

Minnesota Department of Health Monitoring Program

The Radiation Control Unit of the Minnesota Department of Health (MDH) monitors radioactivity 

in Minnesota. Monitoring allows the MDH to develop a database on radioactivity within the state 

that can be used as a baseline during emergencies. As part of the MDH radiological 

environmental program, gamma radiation samples are collected near PINGP 1 and 2 and the 

Monticello Nuclear Generating Plant, located in Wright County. The MDH Public Health 

Laboratory performs radiochemical analysis to estimate doses emitted from the plants. Surveys

of spent fuel storage casks are also performed as part of this program. The MDH 

Environmental Radiation Data Report for 2006 states that, “In 2006, no Federal or state 

standards or guidelines were exceeded anywhere in the state of Minnesota, including near the 

nuclear power generating plants” (MDH 2006). Data from this program indicates that levels of 

Strontium-90 in milk (an aftermath of historic above ground nuclear testing and the Chernobyl 

Nuclear Power Plant accident in Ukraine), are low and now below the detection limit of isotopic 

analysis equipment; levels of Strontium-90 in the environment will continue to decline with 

isotopic decay. MDH also monitors levels surrounding the Independent Spent Fuel Storage 

Installation (ISFSI) at PINGP 1 and 2. MDH data indicates that neutron levels increased 

between 2006 and 2007, which is attributed to the addition of two casks to the ISFSI in 2006. 

Monthly reports for the PINGP 1 and 2 ISFSI are prepared by MDH Radiation Control Unit and 

provide data on radiation levels surrounding the PINGP 1 and 2 ISFSI (MDH 2008).

In addition to MDH’s monitoring program, Wisconsin Public Health Statute §254.41 mandates 

the Department of Health Services to conduct environmental radiation monitoring around 

nuclear power facilities that impact Wisconsin in collaboration with the Radiation Protection 

Section of the Wisconsin Department of Health Services (WIDHS), the Division of Public Health, 

and the Bureau of Environmental Health. Therefore, the Wisconsin Department of Health 

Services also conducts an environmental monitoring program around PINGP 1 and 2. The 

program includes collection of various types of samples from air, water and terrestrial exposure 

pathways. Air, precipitation, ambient gamma radiation, surface water, fish, soil, milk, well water, 

and vegetation samples are collected from selected locations at regular intervals (WIDHS 

2008a, 2008b). 

PINGP 1 and 2 Radioactive Effluent Release Program

All nuclear plants were licensed with the expectation that they would release radioactive 

material to both the air and water during normal operation. However, NRC regulations require 

that radioactive gaseous and liquid releases from nuclear power plants must meet radiation 

dose-based limits specified in 10 CFR Part 20, and as low as is reasonably achievable (ALARA) 

criteria in Appendix I to 10 CFR Part 50. Regulatory limits are placed on the radiation dose that 

members of the public can receive from radioactive material released by a nuclear power plant. 

In addition, nuclear power plants are required to file an annual report to the NRC which lists the 

types and quantities of radioactive effluents released into the environment. The radioactive 

effluent release reports are available for review by the public through the ADAMS electronic 

reading room available through the NRC website.
Environmental Impacts of Operation

4-26

The NRC staff reviewed the annual radioactive effluent reports for 2003 through 2007 and the 

most recent report for 2009 (NMC 2004a, 2005a, 2006a, 2007a, 2008a, NSP 2010c). The 

review focused on the calculated doses to a member of the public from radioactive effluents 

released from PINGP 1 and 2. Historical data on radioactive releases from PINGP 1 and 2 and 

the resultant dose calculations demonstrate that the amount of radiation received by a 

maximally-exposed individual in the vicinity of PINGP 1 and 2 are a small fraction of the dose 

limits specified in 10 CFR Part 20, the ALARA dose design objectives in Appendix I to 

10 CFR Part 50, and EPA radiation standards contained in 40 CFR 190. The dose values were 

calculated based on actual liquid and gaseous effluent release data and conservative models to 

simulate the transport mechanisms. A summary of the calculated maximum dose to an 

individual located at the PINGP 1 and 2 site boundary from liquid and gaseous effluents 

released during 2009 is as follows:

• The calculated maximum total body dose to an offsite member of the general 

public from liquid effluents from each PINGP reactor unit in 2009 was 

9.55E-04 mrem (9.55E-06 mSv). The dose is well below the 3 mrem (0.03 mSv) 

dose design objective in Appendix I to 10 CFR Part 50.

• The calculated maximum organ (GI tract) dose to an offsite member of the 

general public from liquid effluents from each PINGP reactor unit in 2009 was 

3.45E-03 mrem (3.45E-05 mSv). The dose is well below the 10 mrem 

(0.10 mSv) dose design objective in Appendix I to 10 CFR Part 50.

• The calculated maximum gamma air dose at the site boundary from noble gas 

discharges from each PINGP reactor unit was 4.11E-05 mrad (4.11E-07 mGy). 

The dose is well below the 10 mrad (0.10 mGy) dose design objective in 

Appendix I to 10 CFR Part 50.

• The calculated maximum beta air dose at the site boundary from noble gas 

discharges from each reactor unit was 4.49E-03 mrad (4.49E-05 mGy). The 

dose is well below the 20 mrad (0.20 mGy) dose design objective in Appendix I 

to 10 CFR Part 50.

Based on its review of PINGP 1 and 2’s doses to members of the public from radioactive 

effluents, the staff found that PINGP 1 and 2 are operating in compliance with Federal radiation 

protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 

40 CFR Part 190.

Routine plant operational and maintenance activities currently performed will continue during 

the license renewal term. Based on the past performance of the radioactive waste system to 

maintain the dose from radioactive effluents to be ALARA and because continued compliance 

with regulatory requirements is expected during the license renewal term, the impacts to human 

health from radioactive effluents are not expected to change.

Based on the applicant’s assertion of planned refurbishment activities (i.e., replacement of 

Unit 2 steam generators), none to minimal radiological human health impacts are expected from 

PINGP 1 and 2 during the license renewal period. This conclusion is based on past regulatory 

compliance that demonstrates that the dose to a maximally-exposed individual in the vicinity of 

PINGP 1 and 2 has been a small fraction of the limits and standards specified in 

10 CFR Part 20, Appendix I to 10 CFR Part 50, and 40 CFR Part 190. Refurbishment is 

addressed in Chapter 3 of this SEIS.

Additionally, the NRC is aware that the applicant intends to request approval to increase the 

licensed reactor core thermal power level by approximately 10 percent. A change in power level 

requires NRC approval prior to its implementation. As part of the NRC’s license amendment 
Environmental Impacts of Operation

4-27

process, the staff will perform a thorough evaluation of the safety, radiological, and 

environmental issues associated with the proposed power increase to verify that all regulatory 

requirements are met. NSP has not yet submitted its license amendment request for the NRC’s 

review, so the staff is unable to perform a thorough evaluation of the radiological impact at this 

time. However, it can be stated that the radiological impact to human health from the operation 

of the plant after a power increase is required to remain within the NRC’s radiation dose limits in 

10 CFR Part 20, the ALARA dose criteria in Appendix I to 10 CFR Part 50, and EPA’s 

40 CFR Part 190 dose standards.

The radiological impacts from the current operation of PINGP including those from reasonably 

foreseeable changes (i.e., steam generator replacement, power uprate, and ISFSI) to the plant 

are not expected to change significantly. Continued compliance with regulatory dose 

requirements is expected during the license renewal term; therefore, the radiological impact to 

human health would be SMALL.

4.8.2 Microbiological Organisms – Public Health

Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 lists the effects of thermophilic 

microbiological organisms on human health as a Category 2 issue, requiring a plant-specific 

evaluation before license renewal for those plants using cooling towers that are located on a 

small river. NRC specifies in 10 CFR 51.53(c)(ii)(G) that small rivers are those with an average 

annual flow rate less than 3.15x1012 ft3

/yr (9x1010 m3/yr). The average annual flow rate of the 

Mississippi River at the nearest measuring station to PINGP 1 and 2 is 5.8x1011 ft3

/yr (1.64x1010 

m3/yr), therefore the Mississippi River at PINGP 1 and 2 is considered a small river (NMC 2008). 

Recreational uses of the Mississippi River in the vicinity of PINGP 1 and 2, which include 

boating, fishing, and swimming, create the potential for human exposure to thermophilic 

microbiological organisms (NMC 2008). Consequently, the effects of PINGP 1 and 2 thermal 

discharge on microbiological organisms must be addressed for license renewal.

The Category 2 designation is based on the magnitude of the potential public health impacts 

associated with thermal enhancement of enteric pathogens such as Salmonella spp. and 

Shigella spp., the Pseudomonas aeruginosa bacterium, the pathogenic strain of the free-living 

amoebae Naegleria spp., and a number of species from the Legionella genus (NRC 1996). 

Thermophilic microbiological organisms generally occur at temperatures of 77 to 176 degrees 

Fahrenheit (°F; 25 to 80 degrees Celsius [°C]), with optimal growth occurring at temperatures 

from 122 to 150 °F (50 to 66 °C), and a minimum temperature tolerance of 68°F (20 °C) (Joklik 

and Willett 1976). However, thermal preference and tolerances vary across the bacterial family. 

In the GEIS, the NRC staff noted that impacts of nuclear plant thermal discharges are 

considered to be of small significance if they do not enhance the presence of microorganisms 

that are detrimental to water quality and public health (NRC 1996).

P. aeruginosa is an opportunistic pathogen that causes serious and sometimes fatal infections 

in immunocompromised individuals by producing and releasing toxins. It has an optimal growth 

temperature of 99 °F (37 °C) (Todar 2007). The Legionella genus consists of at least 46 species 

and 70 serogroups and is responsible for Legionnaires’ disease, with the onset of pneumonia in 

the first 2 weeks of exposure. Risk groups for Legionella spp. include the elderly, cigarette 

smokers, persons with chronic lung or immunocompromising diseases, and persons receiving

immunosuppressive drugs. Legionella spp. grows best at 90 to 105 °F (32 to 41 °C) (CDC 

2007a). Salmonella typhimurium and S. enteritidis are two of the more common species of 

Enterobacteriaceae, which cause fever, abdominal cramps, and diarrhea. Salmonella spp. can 

occasionally establish localized infection (e.g., septic arthritis) or can progress to sepsis. All 

ages of individuals can be affected, but groups at greatest risk for severe or complicated 
Environmental Impacts of Operation

4-28

disease include infants, the elderly, and immunocompromised persons. Salmonella spp. occurs 

at temperatures between 50 and 120 °F (10 and 49 °C) (CDC 2007b), with optimal growth 

occurring at 95 to 99 °F (35 to 37 °C) (ESR 2002). The pathogenic amoeba flagellate Naegleria 

fowleri is the causative agent of a rapidly fatal form of encephalitis, primary amoebic 

meningoencephalitis (PAM). Naegleria spp. is ubiquitous in nature and can be enhanced in 

thermally-altered water bodies at temperatures ranging from 95 to 106 °F (35 to 41 °C) or 

higher. This organism is rarely found in water cooler than 95 °F (35 °C), and infection rarely 

occurs at these water temperatures (Tyndall et al. 1989). It is estimated that individual annual 

risks to swimmers from PAM caused by the free-living N. fowleri are very low (approximately 

4x10-6

); however, there have been reported cases of fatal Naegleria infections associated with 

power plant cooling towers (NRC 1996).

As discussed in Chapter 2, the PINGP 1 and 2 circulating water system dissipates heat from the 

reactors to the Mississippi River by using one of three modes: open cycle (once-through 

cooling, with no cooling towers in operation), helper cycle (once-through cooling, with 

mechanical draft cooling towers in operation), and closed cycle (using cooling towers to 

recirculate up to 95 percent of the cooling water). The mode of cooling operation is selected by 

the applicant to ensure compliance with the thermal limits of PINGP 1 and 2 NPDES permit No. 

MD0004006 (MPCA 2006; NMC 2008). 

The PINGP 1 and 2 NPDES permit specifies that during the warmer part of the year — from 

April 1 through the date when the daily average upstream ambient river temperature falls below 

43 °F (6 °C) for five consecutive days (the Fall Trigger date) —cooling towers must be operated 

as necessary so that:

• Receiving water is not raised by more than 5 °F (2.8 °C) above ambient temperature;

• Cooling water discharge does not exceed a daily average temperature of 86 °F (30 °C); 

and

• If the daily average ambient temperature reaches 78 °F (26 °C) for two consecutive 

days, all cooling towers shall be operated to the maximum extent practicable (MPCA 

2006).

To comply with these NPDES permit limitations, PINGP 1 and 2 monitors Mississippi River 

water temperature at five locations: the discharge canal, the intake structure, the main river 

channel (upstream), Sturgeon Lake (upstream), and immediately downstream of Lock and Dam 

3. From 2000 through 2005, the highest ambient river water temperature upstream of the 

discharge canal was 86.0 °F (30 °C), measured in August 2001. The highest temperature 

downstream of the discharge canal was 86.4 °F (30.2 °C), measured on the same day. The 

highest temperature measured at the PINGP 1 and 2 discharge canal was 99 °F (37.2 °C), in 

August 2003 (NMC 2008). 

Maximum temperatures in the discharge canal could allow for the presence of thermophilic 

microbiological organisms. However, because the growth rate for microbiological organisms is 

measured in hours and days (Hendricks 1972), it is not expected that the short period of time in 

which the heated discharge water moves through the discharge canal would allow for any 

noticeable impact on growth rates of microbiological organisms. As such, potential thermophilic 

microbiological organisms present in the discharge canal would likely be in limited numbers and 

would not be expected to cause a significant risk to public health. Furthermore, the PINGP 1 

and 2 discharge canal and adjacent portions of the Mississippi River are within the plant’s 

exclusion area boundary (see Figure 2-2 in Chapter 2), and there is no public access to these 

areas. Beyond the discharge canal, maximum ambient river water temperatures are well outside 
Environmental Impacts of Operation

4-29

the optimal temperature range for growth and reproduction of thermophilic microbiological 

organisms. 

Available data assembled by the U.S. Center for Disease Control and Prevention (CDC) for the 

years 1978 through 2006 report no occurrence of waterborne disease outbreaks in Minnesota 

resulting from the operation of PINGP 1 and 2 (CDC 2008). During the most recent two-year 

reporting summary (2005 to 2006), Minnesota reported nine waterborne-disease outbreaks, the 

highest number of outbreaks reported by any state (followed by New York and Florida each 

reporting seven outbreaks, and Wisconsin reporting six). The etiological agents responsible for 

these outbreaks were P. aeruginosa, pool chemicals or disinfection by-products, 

Cryptosporidium hominis (an obligate parasite that colonizes the human gastrointestinal tract), 

Legionella pneumophilla, elevated Escherichia coli levels, Shigella sonnei, Norovirus, and an 

unidentified Vibrio species. All waterborne-disease outbreaks reported during 2005 to 2006 

summary period resulted from the use of a hotel or private pool or spa (treated water), or a 

recreational beach (untreated water) (CDC 2008). 

The staff independently reviewed the applicant’s ER (NMC 2008) and the applicant’s Minnesota 

NPDES permit (MPCA 2006). Based on the evaluation presented above, the staff concludes 

that thermophilic microbiological organisms are not likely to present a public health hazard as a 

result of PINGP 1 and 2 discharges to the Mississippi River, and the staff classifies the 

expected impacts on public health from thermophilic microbiological organisms from continued 

operation of PINGP 1 and 2 in the license renewal period as SMALL. In addition to maintaining 

the current plant exclusion zone to restrict access to the Mississippi River shores in the vicinity 

of the plant discharge canal, the staff identified one additional measure that could mitigate 

potential thermophilic microbiological organism impacts resulting from continued operation of 

PINGP 1 and 2. Periodic monitoring for thermophilic microbiological organisms in the water and 

sediments in and near the discharge canal could reduce human health impacts by minimizing 

the potential for public exposures to these organisms. The staff did not identify any cost-benefit 

studies applicable to this mitigation measure.

4.8.3 Electromagnetic Fields – Acute Shock

Based on the GEIS, the Commission found that electric shock resulting from direct access to 

energized conductors or from induced charges in metallic structures has not been a problem at 

most operating plants and generally is not expected to be a problem during the period of 

extended operation. However, a site-specific review is required to determine the significance of 

the electric shock potential along the portions of the transmission lines within the scope of the 

SEIS.

The GEIS states that it is not possible to determine the significance of the electric shock 

potential without a review of the conformance of each nuclear plant transmission line with the 

National Electrical Safety Code (IEEE 2007) criteria. Evaluation of individual plant transmission 

lines is necessary because the issue of electric shock safety was not addressed in the licensing 

process for some plants. For other plants, land use in the vicinity of transmission lines may have 

changed, or power distribution companies may have chosen to upgrade line voltage. To comply 

with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an assessment of the potential shock 

hazard if the transmission lines that were constructed for the specific purpose of connecting the 

plant to the transmission system do not meet the recommendations of the National Electric 

Safety Code for preventing electric shock from induced currents.

All transmission lines associated with PINGP 1 and 2 were constructed in accordance with 

National Electric Safety Code and industry guidance in effect at that time (AEC 1973). The 

transmission facilities are maintained to ensure continued compliance with current standards. 
Environmental Impacts of Operation

4-30

Routine ground inspections and aerial patrols are performed in order to identify any ground 

clearance problems and the integrity of the transmission lines structures (NMC 2008). Since the 

lines were constructed, a new criterion has been added to the National Electric Safety Code for 

power lines with voltages exceeding 98 kV. This criterion requires that the minimum clearance 

for a line must limit induced currents due to static effects to 5 mA. NSP has reviewed the 

transmission lines for compliance with this criterion and indicated that all transmission lines 

within the scope of this review have been reviewed and results show there are no locations 

under the transmission lines that have the capacity to induce more than 5 mA in a vehicle 

parked beneath the line (NMC 2008). No induced shock hazard to the public should occur, since 

the lines are operating within original design specifications and meet current National Electric 

Safety Code clearance standards.

The NRC staff has reviewed the available information, including the applicant’s evaluation and 

computational results. Based on this information, the NRC staff evaluated the potential impacts 

for electric shock resulting from operation of PINGP 1 and 2 and its associated transmission 

lines. The NRC staff concludes that the potential impacts from electric shock during the renewal 

period would be SMALL. 

4.8.4 Electromagnetic Fields – Chronic Effects

The NRC specifies in 10 CFR 51, Subpart A, Appendix B, Table B-1, that “biological and 

physical studies of 60-Hz electromagnetic fields have not found consistent evidence linking 

harmful effects with field exposure. However, research is continuing in this area and a 

consensus scientific view has not been reached.” The GEIS did not designate the chronic 

effects of 60-Hz electromagnetic fields from power lines as Category 1 or 2; such a designation 

will not occur until a scientific consensus is reached on the health implications of these fields.

The potential for chronic effects from these fields continues to be studied and is not known at 

this time. The National Institute of Environmental Health Sciences (NIEHS) directs related 

research through the U.S. Department of Energy (DOE). The report by NIEHS (1999) contains 

the following conclusion, which is supported by the recently published World Health 

Organization (2007) Environmental Health Criteria Monograph No.238:

The NIEHS concludes that ELF-EMF [extremely low frequency-electromagnetic 

field] exposure cannot be recognized as entirely safe because of weak scientific 

evidence that exposure may pose a leukemia hazard. In our opinion, this finding 

is insufficient to warrant aggressive regulatory concern. However, because 

virtually everyone in the United States uses electricity and therefore is routinely 

exposed to ELF-EMF, passive regulatory action is warranted such as a continued 

emphasis on educating both the public and the regulated community on means 

aimed at reducing exposures. The NIEHS does not believe that other cancers or 

non-cancer health outcomes provide sufficient evidence of a risk to currently 

warrant concern.

This statement is not sufficient to cause the NRC staff to change its position with respect to the 

chronic effects of electromagnetic fields. This position is expressed in Footnote 5 to Table B-1 of 

Appendix B to Subpart A of 10 CFR Part 51 as follows:

If in the future, the Commission finds that, contrary to current indications, a 

consensus has been reached by appropriate Federal health agencies that there 

are adverse health effects from electromagnetic fields, the Commission will 

require applicants to submit plant-specific reviews of these health effects as part 

of their license renewal applications. Until such time, applicants for license 

renewal are not required to submit information on this issue.
Environmental Impacts of Operation

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The NRC staff considers the GEIS finding of “Uncertain” still appropriate and will continue to 

follow developments on this issue.

4.9 Socioeconomics

The socioeconomic issues applicable to PINGP 1 and 2 follow in Table 4.12 for Category 1, Category 

2, and uncategorized issues.

Table 4-12. Socioeconomic Issues. Section 2.2.9 of this report describes the 

socioeconomic conditions near PINGP 1 and 2.

Issues GEIS Section Category

Housing Impacts 4.7.1 2

Public Services: public safety, 

social services, and tourism and 

recreation

4.7.3; 4.7.3.3; 4.7.3.4; 4.7.3.6 1

Public Services: public utilities 4.7.3.5 2

Public Services: education 

(license renewal term)

4.7.3.1 1

Offsite Land Use (license 

renewal term)

4.7.4 2

Public Services: transportation 4.7.3.2 2

Historic and Archaeological 

Resources

4.7.7 2

Aesthetic Impacts (license 

renewal term)

4.7.6 1

Aesthetic impacts of transmission 

lines (license renewal term)

4.5.8 1

Environmental Justice Not addressed (a) Uncategorized (a)

(a)Guidance related to environmental justice was not in place at the time the GEIS and the associated 

revisions to 10 CFR Part 51 were prepared. Therefore, environmental justice must be addressed in 

plant-specific reviews.

4.9.1 Generic Socioeconomic Issues

The NRC staff reviewed and evaluated the PINGP 1 and 2 ER, scoping comments, other 

available information, and visited the PINGP 1 and 2 site. The NRC staff did not identify any 

new and significant information that would change the conclusions presented in the GEIS. 

Therefore, it is expected that there would be no impacts related to the Category 1 issues during 

the period of extended operation beyond those discussed in the GEIS. For PINGP 1 and 2, the 

staff incorporates the GEIS conclusions by reference. Impacts for Category 2 and uncategorized 

issues are discussed in Sections 4.9.2 through 4.9.7, below.

4.9.2 Housing Impacts

Appendix C, Section C.1.4, of the GEIS presents a population characterization method based 

on two factors, sparseness and proximity. Sparseness measures population density within 20 
Environmental Impacts of Operation

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mi (32 km) of the site, and proximity measures population density and city size within 50 mi (80 

km). Each factor has categories of density and size (GEIS, Table C.1). A matrix is used to rank 

the population category as low, medium, or high (GEIS, Figure C.1).

According to the 2000 Census, approximately 107,131 people lived within 20 mi (32 km) of 

PINGP 1 and 2, which equates to a population density of 85 persons per mi2 (142 persons per 

km2

) (NMC 2008). This density translates to the less sparse GEIS Category 3 (60 to 120 

persons per mi2 [100 to 200 persons per km2

] or less than 60 persons per mi2 [100 persons per 

km2

] with at least one community with 25,000 or more persons within 20 mi [32 km]). 

Approximately 2,733,326 people live within 50 mi (80 km) of PINGP 1 and 2 (NMC 2008). This 

equates to a population density of 349 persons per mi2 (582 persons per km2

). Applying the 

GEIS proximity measures, this density is classified as proximity Category 4 (greater than or 

equal to 190 persons per mi2 [317 persons per km2

] within 50 mi [80 km]). Therefore, according 

to the sparseness and proximity matrix presented in the GEIS, the rankings of sparseness 

(Category 3) and proximity (Category 4) result in the conclusion that PINGP 1 and 2 are located 

in a high population area.

Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 states that impacts on housing 

availability are expected to be of small significance in high-density population areas where 

growth control measures are not in effect. Since the PINGP 1 and 2 site is located in a high 

population area, and Goodhue and Dakota Counties, Minnesota, and Pierce County, Wisconsin, 

are not subject to growth control measures that would limit housing development, any changes 

in employment at PINGP 1 and 2 would have little noticeable effect on housing availability in 

these counties. Since NSP has no plans to add non-outage employees during the license 

renewal period, employment levels at PINGP 1 and 2 would remain relatively constant with no 

additional demand for permanent housing during the license renewal term. In addition, the 

number of available housing units has kept pace with or exceeded the increase in area 

population. Based on this information, there would be no impact on permanent housing during 

the license renewal term beyond what has already been experienced.

However, NSP indicated in their environmental report that the PINGP, Unit 2, steam generators 

would be replaced prior to the license renewal term. NSP estimates that steam generator 

replacement would require a one-time increase in the number of refueling outage workers for up 

to 80 days at PINGP 1 and 2 (NMC 2008). These additional workers would create an additional 

demand for temporary (rental) housing in the immediate vicinity of PINGP 1 and 2. The impacts 

of the PINGP, Unit 2, steam generator replacement are discussed in Chapter 3 of this SEIS.

4.9.3 Public Services: Public Utility Impacts

Impacts on public utility services are considered SMALL if there is little or no change in the 

ability of the system to respond to demand and thus there is no need to add capital facilities. 

Impacts are considered MODERATE if service capabilities are overtaxed during periods of peak 

demand. Impacts are considered LARGE if services (e.g., water, sewer) are substantially 

degraded and additional capacity is needed to meet ongoing demand. In the absence of new 

and significant information to the contrary, the only impacts on public utilities that could be 

significant would be impacts on public water supplies.

Analysis of impacts on the public water systems considered both plant demand and plantrelated population growth. Section 2.1.3 of this SEIS describes the permitted withdrawal rate 

and actual use of water for reactor cooling for PINGP 1 and 2. 

Since NSP has no plans to add non-outage employees during the license renewal period, 

employment levels at PINGP 1 and 2 would remain relatively unchanged with no additional 

demand for public water and sewer services. Public water systems in the region would be 
Environmental Impacts of Operation

4-33

adequate to meet the demands of residential and industrial customers in the area. Therefore, 

there would be no additional impact to public water and sewer services during the license 

renewal term beyond what is currently being experienced.

As discussed in Section 4.9.2, NSP indicated in their environmental report that the PINGP 1 and 

2, Unit 2, steam generators would be replaced prior to the license renewal term (NMC 2008). 

The additional number of refueling outage workers needed to replace the steam generators 

would cause a short-term increase in the amount of public water and sewer services used in the 

immediate vicinity of PINGP 1 and 2. These impacts are discussed in Chapter 3 of this SEIS.

4.9.4 Offsite Land Use – License Renewal Period

Offsite land use during the license renewal term is a Category 2 issue (10 CFR 51, Subpart A, 

Appendix B, Table B-1). Table B-1 of 10 CFR 51 Subpart A, Appendix B notes that “significant 

changes in land use may be associated with population and tax revenue changes resulting from 

license renewal.”

Section 4.7.4 of the GEIS defines the magnitude of land-use changes as a result of plant 

operation during the license renewal term as follows:

SMALL - Little new development and minimal changes to an area's land-use pattern.

MODERATE - Considerable new development and some changes to the land-use pattern.

LARGE - Large-scale new development and major changes in the land-use pattern.

Tax revenue can affect land use because it enables local jurisdictions to provide the public 

services (e.g., transportation and utilities) necessary to support development. Section 4.7.4.1 of 

the GEIS states that the assessment of tax-driven land-use impacts during the license renewal 

term should consider (1) the size of the plant’s payments relative to the community’s total 

revenues, (2) the nature of the community’s existing land-use pattern, and (3) the extent to 

which the community already has public services in place to support and guide development. If 

the plant’s tax payments are projected to be small relative to the community’s total revenue, taxdriven land-use changes during the plant’s license renewal term would be SMALL, especially 

where the community has pre-established patterns of development and has provided adequate 

public services to support and guide development. Section 4.7.2.1 of the GEIS states that if tax 

payments by the plant owner are less than 10 percent of the taxing jurisdiction’s revenue, the 

significance level would be SMALL. If the plant’s tax payments are projected to be medium to 

large relative to the community’s total revenue, new tax-driven land-use changes would be 

MODERATE. If the plant’s tax payments are projected to be a dominant source of the 

community’s total revenue, new tax-driven land-use changes would be LARGE. This would be 

especially true where the community has no pre-established pattern of development or has not 

provided adequate public services to support and guide development.

Since NSP has no plans to add non-outage employees during the license renewal period, there 

would be minimal plant operations-driven population increase in the vicinity of PINGP 1 and 2. 

Therefore, there would be minimal population-related land use impacts during the license 

renewal term beyond what has already been experienced.

Population-related Impacts

As discussed in Section 4.9.2, NSP indicated in their environmental report that the PINGP, Unit 

2, steam generators would be replaced prior to the license renewal term (NMC 2008). Due to 

the short amount of time needed to replace the steam generators, the additional number of 

refueling outage workers would not cause any permanent population-related land use changes 
Environmental Impacts of Operation

4-34

in the immediate vicinity of PINGP 1 and 2. These impacts are discussed in Chapter 3 of this 

SEIS.

As previously discussed in Chapter 2, NSP pays annual real estate taxes to Goodhue County, 

City of Red Wing, and School District 256. For the three-year period from 2003 through 2005, 

tax payments to Goodhue County represented 17 to 21 percent of the County’s total annual 

property tax revenues, and payments to the City of Red Wing represented approximately 36 to 

42 percent of the City’s total annual property tax revenues. NSP’s tax payments to School 

District 256, for the period 2003 through 2005, represented 28 to 36 percent of the District’s total 

annual property tax revenues.

Tax-Revenue-Related Impacts

Since NSP started making payments to local jurisdictions, population levels and land use 

conditions in Goodhue County and the City of Red Wing have not changed significantly, which 

might indicate that these tax revenues have had little or no effect on land use activities within 

the county or city. Given that NSP has no plans to add non-outage employees during the 

license renewal period, employment levels at PINGP 1 and 2 would remain relatively 

unchanged. The assessed value of PINGP 1 and 2 is not expected to increase, and annual 

property tax payments to Goodhue County, City of Red Wing, and School District 256 are

expected to remain relatively unchanged throughout the license renewal period. Based on this 

information, there would be no significant land use impacts related to tax revenue during the 

license renewal term beyond what has already been experienced.

As discussed in Section 4.9.2, NSP indicated in their ER that the PINGP, Unit 2, steam 

generators would be replaced prior to the license renewal term (NMC 2008). The replacement 

of the existing steam generators could likely increase the assessed value of PINGP 1 and 2, 

and property tax payments could increase. These and other tax-revenue related impacts are 

discussed in Chapter 3 of this SEIS.

4.9.5 Public Services: Transportation Impacts

Table B-1 of 10 CFR Part 51 states: “Transportation impacts (level of service) of highway traffic 

generated...during the term of the renewed license are generally expected to be of small 

significance. However, the increase in traffic associated with additional workers and the local 

road and traffic control conditions may lead to impacts of moderate or large significance at some 

sites.” All applicants are required by 10 CFR 51.53(c) (3)(ii)(J) to assess the impacts of highway 

traffic generated by the proposed project on the level of service of local highways during the 

term of the renewed license. 

Since NSP has no plans to add non-outage employees during the license renewal period, there 

would be no noticeable change in traffic volume and levels of service on roadways in the vicinity 

of PINGP 1 and 2. Therefore, there would be minimal transportation impacts during the license 

renewal term beyond what is currently being experienced.

As discussed in Section 4.9.2, NSP indicated in their environmental report that the PINGP 1 and 

2, Unit 2, steam generators would be replaced prior to the license renewal term (NMC 2008). 

The additional number of refueling outage workers and truck material deliveries needed to 

support the replacement of the steam generators would cause a short-term transportation 

impact on access roads in the immediate vicinity of PINGP 1 and 2. These impacts are 

discussed in Chapter 3 of this SEIS.

Prairie Island Indian Community

The following information was provided by the PIIC (PIIC 2008).
Environmental Impacts of Operation

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As stated in Chapter 2 and 3, the Tribe is concerned about PINGP 1 and 2-

related traffic impacts on the Tribe’s residential area (60 homes), the casino 

(guests and employees) and the tribal government offices, especially the 

increased volume of traffic that occurs during plant outages. Sturgeon Lake Road 

provides the only access to the Tribe’s residential area, its government center, 

and its business. PINGP 1 and 2 full-time employees and outage workers also 

heavily use Sturgeon Lake Road.

4.9.6 Historic and Archaeological Resources

The National Historic Preservation Act (NHPA) requires Federal agencies to consider the effects 

of their undertakings on historic properties. Historic properties are defined as resources that are 

eligible for listing on the NRHP. The criteria for eligibility are listed in Title 36, “Parks, Forests, 

and Public Property,” Part 60, Section 4, “Criteria for Evaluation,” of the Code of Federal 

Regulations (36 CFR Part 60.4) and include (1) association with significant events in history; (2) 

association with the lives of persons significant in the past; (3) embodies distinctive 

characteristics of type, period, or construction, and (4) or sites or places that have yielded or is 

likely to yield important information (ACHP 2008). The historic preservation review process 

(Section 106 of the NHPA) is outlined in regulations issued by the Advisory Council on Historic 

Preservation (ACHP) in Title 36, “Parks, Forests, and Public Property,” Part 800, “Protection of 

Historic Properties,” of the Code of Federal Regulations (36 CFR Part 800).

The issuance of a renewed operating license for a nuclear power plant is a federal action that 

could possibly affect either known or undiscovered historic properties located on or near the 

plant site and its associated transmission lines. In accordance with the provisions of the NHPA, 

the NRC is required to make a reasonable effort to identify historic properties in the area of 

potential effect. The area of potential effect for a license renewal action is the area at the power 

plant site and its immediate environs that may be impacted during land-disturbing operations or 

projected refurbishment activities associated with the proposed action. If no historic properties 

are present or affected, the NRC is required to notify the State Historic Preservation Office 

before proceeding. If it is determined that historic properties are present, the NRC is required to 

assess and resolve possible adverse effects of the undertaking.

NSP contacted the MNHS in April 2007 to request information on historic and archaeological 

resources in the vicinity of the PINGP 1 and 2 site and describe the proposed action (license 

renewal) (NMC 2007a). The MNHS responded requesting additional information about the 

license renewal process, and NSP provided additional information in March 2008 (NMC 2008a). 

In response to NSP’s request, the MNHS stated, in a letter dated April 29, 2008, that many 

known archaeological sites are located on and in the vicinity of PINGP 1 and 2. MNHS noted 

that many of these sites had been disturbed by the construction of PINGP 1 and 2. MNHS also 

requested that NSP implement effective and proactive cultural resource management practices 

during the license period, and that a programmatic agreement be negotiated (MNHS 2008).

NSP contacted the PIIC in July 2007 to request the PIIC’s participation in the license renewal 

application process (NMC 2007b). The PIIC submitted a letter to NSP detailing concerns 

regarding the past treatment of historic and archaeological resources and other environmental 

issues at PINGP 1 and 2 (PIIC 2008a).

In accordance with 36 CFR 800.8(c), the NRC contacted the MNHS (NRC 2008a), the ACHP 

(NRC 2008b), the PIIC (2008c) and other Federally-recognized Native American Tribes to 

initiate consultation regarding the Section 106 consultation process. These letters are listed in 

Appendix D. 
Environmental Impacts of Operation

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On April 14, 2008, the NRC received a letter from the PIIC requesting participation as a 

cooperating agency in the license renewal environmental review for PINGP 1 and 2. On June 

17, 2008, the NRC and the PIIC entered into a Memorandum of Understanding (MOU) to 

establish a framework for the NRC and the PIIC to work together to review potential 

environmental impacts of the proposed license renewal. The MOU establishes a cooperating 

agency relationship between the NRC and the PIIC for the preparation of the PINGP 1 and 2 

SEIS.

As discussed in Section 2.2.9, a search of the MNHS, Bureau of Indian Affairs (BIA), and Office 

of the State Archaeologist (OSA) site files identified 13 archaeological sites, including 11 known 

and recorded archaeological sites, and 2 unrecorded sites, the Vergil Larson II Mound Group 

site [21GDI], and the Prairie Island District 132 Schoolhouse (see Table 2.25) at the PINGP 1 

and 2 plant site. The following is a brief description of the known archaeological sites.

Several surveys and archaeological excavations have been conducted over the years at the 

Bartron village site (21GD02). This multi-component site is crucial to understanding the 

emergence and interactions of broadly defined Late Woodland, Oneota, and Mississippian 

cultures and peoples (Hildebrandt Iffert 2010). This site was never impacted by PINGP 

construction activities. A portion of the Bartron village site extends onto the PINGP property. 

This site has been moderately disturbed by cultivation (70%), heavily disturbed by historic and 

modern use (20%), and a small portion has been destroyed (impacted) by archaeological 

excavation (10%) (Hildebrandt Iffert 2010; Boden et. al 2010). Currently, the portion of this site 

located on private property is actively cultivated (Hilldebrandt Iffert 2010.) The Bartron village 

site contains intact features and should be avoided.

The Birch Lake Mound Group (21GD58/61) was initially surveyed in 1885 by T.H. Lewis. Five 

out of eight mounds in this group were excavated as part of Elden Johnson’s survey work in 

1968. prior to and in conjunction with the construction of PINGP 1 and 2. A limited Phase I 

reconnaissance survey of the PINGP 1 and 2 site conducted by Merjent Inc. in 2009 lists the 

condition of the site as heavily disturbed by archaeological excavation (Boden et. al 2010). The 

mounds are discernable only as remnants of Elden Johnson’s excavations and should be 

avoided (Hildebrandt Iffert 2010).

Human remains and funerary objects were recovered from this site (21GD58/61). The PIIC 

requested (through the Minnesota Indian Affairs Council) that the human remains and funerary 

objects removed from this mound group be returned so they can be properly repatriated (PIIC 

2010.) The Minnesota Indian Affairs Council performed a detailed assessment of the human 

remains and associated funerary objects in consultation with representatives of the Flandreau 

Santee Sioux Tribe of South Dakota; Lower Sioux Indian Community in the State of Minnesota;

Portions of this site could still be intact and should be avoided. The PIIC have requested 

(through the Minnesota Indian Affairs Council) that the human remains from this mound group 

be returned so they can be properly repatriated (PIIC 2010).

Statement provided by the Prairie Island Indian Community:

In late 2009, the Prairie Island Indian Community sent a letter to the Minnesota Indian 

Affairs Council (MIAC) requesting the return of human remains and funerary objects that 

were removed from the Birch Lake mound group by Dr. Johnson. The NPS published a 

Federal Register Notice on December 14, 2010, notifying interested parties that the 

remains and funerary objects could be dispositioned to one of the tribes culturally 

affiliated with the Birch Lake site, pursuant to 43 CFR 10.11(c)(1). The Prairie Island 

Indian Community plans to repatriate the human remains and funerary objects during the 
Environmental Impacts of Operation

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spring of 2011. NSPM has offered assistance in preparing the site—clearing brush or 

other debris, and allowing access to the site for the repatriation ceremony. (PIIC 2011)

The NSP II Mound Group (21GD59) consists of six burial mounds and dates to the 

Mississippian period. This mound group was located in the vicinity of the PINGP 1 and 2 

cooling towers. Prior to construction, it was noted that some of the mounds had been originally 

impacted by years of cultivation. In 1968 and 1969, two of the six mounds were excavated: no 

burials were associated with these mounds. Survey reports noted that the mounds did not yield 

significant amounts of cultural artifacts (Johnson, Peterson, and Streiff 1969). The four 

remaining mounds were either heavily disturbed by construction activities (grading) or possibly 

covered with several feet of fill (spoil deposits). . Aerial photos show heavy ground disturbance 

on and in the vicinity of the NSP II Mound Group during the construction of the cooling towers. 

If the mounds were covered with fill, this could have preserved some of the NSP II mound site. 

The exact degree of preservation of this site is unknown. Portions of this site could still be intact 

and should be avoided. Both Hildebrandt Iffert and Boden recommended further extensive 

geophysical testing in order to confirm the presence of this mound group (Hildebrandt Iffert 

2010). Since a portion of this mound group could still be intact, this area should be avoided.

A single elongated mound (Birch Lake Mound 21GD62) was mechanicallyexcavated in July 

1969 by Elden Johnson. This mound site has been disturbed by years of cultivation and could 

have been impacted by railroad construction. The impact on this particular site from 

construction of PINGP 1 and 2 was minimal because it was located outside the construction 

area. The 2009 limited Phase I reconnaissance survey relocated this site and noted evidence 

of prior archaeological excavation (open trenches and large piles of excavation backdirt) (Boden 

et. al 2010). Archaeological trenches were closed during the summer of 2010. Artifacts 

recovered from this site are currently curated at the MNHS (Hildebrandt Iffert 2010). According 

to the 2009 survey, no visible evidence of the mound or mounds remain and the site form 

indicates that the site was completely destroyed (Boden et. al 2010). No artifacts were 

recovered during the 2009 survey. Nevertheless, there is the potential for additional artifacts to 

be present at this site and this area should be avoided.

In 1980, site 21GD148 (a Late Woodland habitation site) and site 21GD207 (a Late Woodland 

artifact scatter) were identified and excavated during Johnson’s survey for the modification of 

the cooling discharge canal. Site 21GD148 was nominated to the NRHP in 1980, but was not 

listed (Hildebrandt Iffert 2010). This site was revisited during the 2009 limited Phase I 

reconnaissance survey. A single lithic flake was observed (Boden et. al 2010). No other 

cultural materials were identified during this survey. The 2009 survey also revisited Site 

21GD207 (Dike site) and noted that both of these sites had been impacted by the construction 

of the canal and cooling towers for PINGP 1 and 2 (Boden et. al 2010). However, portions of 

these sites could be undisturbed and should be avoided.

Also, in 1980, site 21GD149 (Substation site) was recorded eroding out of a river bank by NSP 

biologists on land owned by the USACE and leased by NSP. This site was discovered when 

water levels were lowered (drawdown) in the pool above Lock and Dam No. 3 by the USACE. 

Site 21GD149 was originally reported as and artifact scatter and a possible earthwork, mound, 

or habitation site dating to the Late Woodland and Mississippian periods and has the potential to 

yield important information regarding the relationships between these cultures. (Hildebrandt 

2008; Hildebrandt Iffert 2010.) This site was surveyed in 1980 and could have been excavated 

at that time, though no field notes exist (Hildebrandt Iffert 2010). This site is located on an 

estimated 3.35 acres that spans both state-owned land (80 percent) and land owned by NSP 

(20 percent). The portion of this site that is on NSP property is located in the northern part of 
Environmental Impacts of Operation

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the owner-controlled area, in close proximity to the Mississippi River. This site was revisited 

by Merjent in 2009. No cultural material was observed, and Merjent determined that the earthen 

feature is likely a spoils pile of recent origin (Boden et. al 2010). NSP intends to have this site 

surveyed if future drawdown occurs, thus this site should be avoided. Erosion control measures 

should be implemented to prevent any further damage to this site.

The Indian Slough Mound (21GD277) was discovered during the 2009 limited Phase I 

reconnaissance survey of the PINGP property. This oval shaped mound is located on the edge 

of a cultivated field (Boden et. al 2010). No subsurface testing was conducted at this site and 

no artifacts were found (Hildebrandt Iffert 2010). The degree of disturbance is “minimal” and the 

site appears to be in good condition and relatively intact (Boden et. al 2010). This new site 

should be avoided.

Two historic farmsteads, Otto Phlika Farmstead (21GD278) and the Kuhns Farmstead 

(21GD279), were also identified during the 2009 limited Phase I reconnaissance survey. 

Historic artifacts were observed at both sites. At the Phlika site, they found a set of concrete 

steps that may belong to the main farmhouse (Boden et. al 2010). Other historic features 

include two privies, a main cellar, and two additional structures (Hildebrandt Iffert 2010). A 

follow-up survey of the area identified two historical trash dumps. According to its site form, this 

farmstead is listed as being moderately disturbed with poor surface condition (Hildebrandt Iffert 

2010). The Kuhns farmstead is located near a security fence. The site consists of the remnants 

of two (possibly three) structures and associated trash dumps (Hildebrandt Iffert 2010). Both of 

these sites should be avoided. No artifacts were collected from these sites during the 2009 

survey.

The Reliance Stove Door site (21GD280) was discovered during the 2009 limited Phase I 

reconnaissance survey. This multi-component site shows evidence of historic habitation and a 

ricing camp. This site is marked by several surface depressions. Historic artifacts were found 

on the surface including a piece of historic white ware pottery and a Reliance stove door. This 

stove door places the date for this site to about 1847 (Boden et. al 2010). In addition to the 

historic artifacts, one lithic flake was recovered from this site. The site has not been assessed 

for eligibility for listing on the NRHP and has not been subject to archaeological investigations 

and erosion is a current threat to the site (Boden et. al 2010). This site should be avoided.

The Vergil Larson II Mound Group (21GDl), a group of three mounds, was discovered in the 

1980s. A reconnaissance survey was conducted in 1998 and 1999. No subsurface testing was 

conducted out of respect for potential burials interred in the reported mounds. The 2009 limited 

Phase I reconnaissance survey did not find any evidence of these reported mounds, possibly 

due to farming (Boden et. al. 2010.) This area should be avoided.

One potential historic resource is the Prairie Island (District 132) Schoolhouse. The 

schoolhouse was operational from 1873 through 1953 (Hildebrandt 2008, Hilldebrandt Iffert 

2010.) This one room schoolhouse was attended by children who were both local members of 

the PIIC as well as non-Indian children who are not members (PIIC 2008). It was torn down 

during construction of PINGP 1 and 2; however, the foundation remains preserved underneath a 

mowed area. This site has never been formally investigated. This area should be avoided and 

investigated in the event of any ground disturbing activities.

Seven isolated historic spot finds were identified on PINGP property during the 2009 limited 

Phase I reconnaissance survey. These surface finds were recorded, but were not subjected to 

further subsurface testing (Boden, et. al 2010).

NSP has indicated no plans to alter the PINGP 1 and 2 site for license renewal. Nevertheless, 

because there is a high potential for additional historic and archaeological resources to be 
Environmental Impacts of Operation

4-39

discovered at the PINGP 1 and 2 site, NSP should ensure that these resources are not affected 

by continued operations and maintenance activities. 

NSP has revised its corporate procedures to ensure the protection of archaeological resources

at the PINGP 1 and 2 plant site. In addition, NSP implemented the following four license 

renewal commitments to address the protection of archaeological, historical and cultural 

resources at PINGP. These commitments are stated exactly as they were issued by the 

applicant, (reference in the text to NSPM, Xcel, NSP Minnesota and NSP are all referring to the 

applicant, NSP).

New Commitment Number 37

NSPM will revise procedures for excavation and trenching controls and 

archaeological, cultural and historic resource protection to identify sensitive areas 

and provide guidance for ground-disturbing activities. The procedures will be 

revised to include drawings and illustrations to assist users in identifying 

culturally sensitive areas, and pictures of artifacts that are prevalent in the area of 

the Plant site. The revised procedures will also require training of the Site 

Environmental Coordinator and other personnel responsible for proper execution 

of excavation or other ground-disturbing activities (NSP 2009).

New Commitment Number 38

NSPM will conduct a Phase I Reconnaissance Field Survey of the disturbed 

areas within the Plant’s boundaries. In addition, NSPM will conduct Phase I field 

surveys of areas of known archaeological sites to precisely determine their 

boundaries. NSPM will use the results of these surveys to designate areas for 

archaeological protection (NSP 2009).

New Commitment Number 39

NSPM will prepare, maintain and implement a Cultural Resources Management 

Plan (CRMP) to protect significant historical, archaeological, and cultural 

resources that may currently exist on the Plant site. In connection with the 

preparation of the CRMP, NSPM will conduct botanical surveys to identify 

culturally and medicinally important species on the plant site, and incorporate 

provisions to protect such plants into the CRMP (NSP 2009).

New Commitment Number 40

NSPM will consult with a qualified archaeologist prior to conducting any grounddisturbing activity in any area designated as undisturbed and in any disturbed 

area that is described as potentially containing archaeological resources (as 

determined by the Phase I Reconnaissance Field Survey discussed in New 

Preliminary Commitment Number 38) (NSP 2009).

Since the draft SEIS was issued in October 2009, all of these commitments have been 

implemented by NSP. In addition, NSP received comments from the MNHS, BIA, the OSA, and 

the PIIC on its revised procedures. These revised procedures have since been finalized and 

implemented. 

During the environmental site audit, NRC staff discovered that Excavation and Trenching 

Control procedures have not been consistently applied at PINGP 1 and 2. An excavation was 

found near an existing archaeological site, and it was determined that NSP’s procedures had 

not been followed. NSP initiated corrective actions which include the training of employees and 

staff (NSP 2009). In addition, as previously discussed in Chapter 2 of this SEIS, NSP will 
Environmental Impacts of Operation

4-40

conduct a Phase I Reconnaissance Field Survey of disturbed areas and known archaeological 

sites (Xcel 2009).

Based on the review of MNHS, OSA, and BIA files, information from the PIIC; archaeological 

surveys, assessments, and other information; the potential impacts of continued operations and 

maintenance of PINGP 1 and 2 on historic, archaeological, and cultural resources could be 

MODERATE. NSP could mitigate MODERATE impacts by training NSP staff in the Section 106 

consultation process and cultural awareness training to ensure that informed decisions are 

made when considering the effects of continued operations and maintenance on historic and 

archaeological resources. In addition, NSP would also develop a cultural resources 

management plan which would coordinate procedures, policies, and effectively manage and 

protect the archaeological sites and resources on the PINGP 1 and 2 site. The cultural 

resources management plan should be developed in consultation with the NRC, PIIC, OSA, 

BIA, and MHS. NSP should also establish a point of contact to facilitate open communication 

with the PIIC regarding activities that could impact historic and archaeological resources.

Prairie Island Indian Community

The following information was provided by the PIIC (PIIC 2011).

All of the archaeological sites on Prairie Island (including those within the boundaries of 

PINGP 1 and 2) are considered by Tribal members to be sacred sites. Subsequent to 

the issuance of the draft SEIS (November 2009), we were dismayed to learn that many 

of the archaeological sites within the PINGP 1 and 2 were desecrated by the 

archaeologist hired by NSP to conduct archaeological studies in advance of plant 

construction. Much of this work was considered to be a salvage operation. “Salvage 

operations” were usually undertaken when there was an imminent threat of destruction 

(from construction) to archaeological sites. That is, sites were excavated and human

Two mound sites that were excavated in the late 1960s were never properly closed and 

were left open after the archaeological studies were completed. That these burial sites 

were abandoned and left open for 40-plus years is an insult to our Community. Both of 

these sites are well outside the immediate construction zone. There is no reasonable 

explanation why the archaeologist hired by NSP was conducting “salvage operations” in 

this area other than his own research ambitions, which were supported by NSP. 

remains and other objects were removed from sites before construction occurred. Two of 

the sites impacted by these “salvage operations” were well away from the construction 

zone. 

Site 21GD62 was excavated using mechanical trencher; the trenches were never 

properly closed and were left open until June 2010. 

At Site 21GD58/61, the archaeologist hired by NSP removed human remains and 

funerary objects and left these excavation units open as well (these units are still open). 

The PIIC plans to repatriate the human remains and funerary objects during the spring of 

2011.

It is ironic that in his effort to “save” the archaeological sites during the construction of 

the PINGP 1 and 2, the archaeologist hired by NSP may have irreparably disturbed 

these important archaeological resources. 

Site 21GD59 was severely damaged during the construction of the cooling towers. Four 

mounds were either covered with fill or leveled during construction of the PINGP’s 
Environmental Impacts of Operation

4-41

cooling towers. The statement “no human remains were encountered” does not mitigate 

the damage caused by NSP. These were the graves of human beings. We have yet to 

know what NSP intends to do to rectify the situation.

The Prairie Island Indian Community developed its portion of the SEIS through the lens 

of past activities at the PINGP and the cumulative and integrated impacts on the Tribe, 

its people, and its lands as a result of the construction and operation of the PINGP. That 

archaeological sites (i.e., burial sites) were callously desecrated, disturbed, abandoned 

and left open for 40-plus years makes it difficult for the Community to see how the 

presence of the PINGP is of any benefit to the Community. 

4.9.7 Environmental Justice

Under Executive Order 12898 (59 FR 7629), Federal agencies are responsible for identifying 

and addressing potential disproportionately high and adverse human health and environmental 

impacts on minority and low-income populations. In 2004, the Commission issued a Policy 

Statement on the Treatment of Environmental Justice Matters in NRC Regulatory and Licensing 

Actions (69 FR 52040), which states, “[t]he Commission is committed to the general goals set 

forth in Executive Order 12898 (EO), and strives to meet those goals as part of its NEPA review 

process.”

The Council of Environmental Quality (CEQ) provides the following information in Environmental 

Justice: Guidance under the National Environmental Policy Act (NEPA) (1997):

Disproportionately High and Adverse Human Health Effects. Adverse health 

effects are measured in risks and rates that could result in latent cancer fatalities, 

as well as other fatal or nonfatal adverse impacts on human health. Adverse 

health effects may include bodily impairment, infirmity, illness, or death. 

Disproportionately high and adverse human health effects occur when the risk or 

rate of exposure to an environmental hazard for a minority or low-income 

population is significant (as defined by NEPA) and appreciably exceeds the risk 

or exposure rate for the general population or for another appropriate comparison 

group (CEQ 1997).

Disproportionately High and Adverse Environmental Effects. A 

disproportionately high environmental impact that is significant (as defined by 

NEPA) refers to an impact or risk of an impact on the natural or physical 

environment in a low-income or minority community that appreciably exceeds the 

environmental impact on the larger community. Such effects may include

ecological, cultural, human health, economic, or social impacts. An adverse 

environmental impact is an impact that is determined to be both harmful and 

significant (as defined by NEPA). In assessing cultural and aesthetic 

environmental impacts, impacts that uniquely affect geographically dislocated or 

dispersed minority or low-income populations or American Indian tribes are 

considered (CEQ 1997).

The environmental justice analysis assesses the potential for disproportionately 

high and adverse human health or environmental effects on minority and lowincome populations that could result from the operation of PINGP 1 and 2 during 

the renewal term. In assessing the impacts, the following CEQ (1997) definitions 

of minority individuals and populations and low-income population were used:

Minority individuals. Individuals who identify themselves as members of the 

following population groups: Hispanic or Latino, American Indian or Alaska 
Environmental Impacts of Operation

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Native, Asian, Black or African American, Native Hawaiian or Other Pacific 

Islander, or two or more races meaning individuals who identified themselves on 

a Census form as being a member of two or more races, for example, Hispanic 

and Asian.

Minority populations. Minority populations are identified when (1) the minority 

population of an affected area exceeds 50 percent or (2) the minority population 

percentage of the affected area is meaningfully greater than the minority 

population percentage in the general population or other appropriate unit of 

geographic analysis.

Low-income population. Low-income populations in an affected area are 

identified with the annual statistical poverty thresholds from the Census Bureau’s 

Current Population Reports, Series PB60, on Income and Poverty.

According to 2000 Census data, 16.6 percent of the population (approximately 2,743,000 

persons) residing within a 50-mi (80-km) radius of PINGP 1 and 2 identified themselves as 

minority individuals. The largest minority group was Black or African American (185,000 

persons or 6.7 percent), followed by Asian (140,000 persons or about 5.1 percent) (USCB 

2003). About 3.9 percent of the Goodhue County population identified themselves as

minorities, with American Indian and Alaska Native the largest minority group (1.3 percent) 

followed by Hispanic or Latino (1.1 percent) (USCB 2008) (see Table 2.2.8.5–2).

Minority Population in 2000

The 50-mi (80-km) radius around PINGP 1 and 2 includes 25 counties, 17 of which are in 

Minnesota and 8 of which are in Wisconsin. The geographic area includes any census block 

group with all or part of its area within the 50-mi (80-km) radius. Of the 2,197 census block 

groups located wholly or partly within the 50-mi (80-km) radius of PINGP 1 and 2, 312 block 

groups were determined to have high density minority population percentages that exceeded 

the state average by 20 percentage points or more (NMC 2008). The largest number of high 

density minority block groups was Black or African American, with 131 block groups that exceed 

the state average 20 percent or more. These block groups are concentrated in urban areas with 

high population densities. The greatest number of high density block groups with minority 

populations is located in two Minnesota counties (Hennepin and Ramsey). The closest high 

density minority population to PINGP 1 and 2 is located in Minneapolis. Based on 2000 Census 

data, Figure 4-2 shows the location of high density minority block groups within a 50-mi (80-km)

radius of PINGP 1 and 2.

The NRC staff has designated the Prairie Island Indian Community (PIIC) as a minority 

population within a 50-mi (80-km) radius of PINGP 1 and 2. Figure 4-1 shows the boundary of 

the PIIC in relation to the PINGP 1 and 2 site.

According to 2000 Census data, approximately 32,000 families and 99,000 individuals 

(approximately 4.7 and 7.2 percent, respectively) residing within a 50-mi (80-km) radius of 

PINGP 1 and 2 were identified as living below the Federal poverty threshold in 1999 (USCB 

2003). The 1999 Federal poverty threshold was $17,029 for a family of four. 

Low-Income Population in 2000

According to Census data estimates, the median household income for Minnesota in 2005-2007 

was $55,616, with 9.6 percent of the state population living below the Federal poverty threshold. 

For the same time period, Goodhue County had a slightly lower median household income 

average ($55,098) and a lower percentage (7.9 percent) of individuals living below the poverty 

level when compared to the state average. Dakota County had much higher median household 
Environmental Impacts of Operation

4-43

income ($72,393) and a lower percentage (5.3 percent) of individuals living below the poverty 

level when compared to the state and Goodhue County. The median household income for 

Wisconsin in 2005-2007 was $50,309, with 10.8 percent of the state population living below the 

Federal poverty threshold. For the same time period, Pierce County had a higher median 

household income average ($58,011) and a lower percentage (6.9 percent) of individuals living 

below the poverty level when compared to the state average (USCB 2008).

Census block groups were considered high density low-income block groups if the percentage 

of households below the Federal poverty threshold exceeded the state average by 20 percent or 

more. Based on 2000 Census data, there were 89 block groups within the 50-mi (80-km) radius 

of PINGP 1 and 2 that exceeded the state average for low income households by 20 percent or 

more. The majority of census block groups with low-income populations were located in two 

counties, Hennepin County (61 block groups) and Ramsey County (23 block groups) in 

Minnesota. The nearest high density low-income population to PINGP 1 and 2 is located in 

Minneapolis-St. Paul, Minnesota (NMC 2008). Figure 4-3 shows the location of high density 

low-income census block groups within a 50-mi (80-km) radius of PINGP 1 and 2.

As Cooperating Agencies, the NRC staff consulted with the PIIC during its environmental review 

of the proposed license renewal for PINGP 1 and 2 to develop analyses of certain impacts. As a 

result of such consultation, the information presented in this section represents the approaches 

used by NRC staff and PIIC in conducting the analyses of environmental justice. 

Analysis of Impacts

The NRC Staff’s Analysis of Environmental Justice

As discussed earlier, the NRC addresses environmental justice matters for license renewal 

through (1) identification of minority and low-income populations that may be disproportionately 

affected by the proposed license renewal, and (2) examining any human health or 

environmental effects to determine if these effects may be disproportionately high or adverse on 

populations. 

The preceding discussion and Figures 4-2 and 4-3 identifies the location of minority and 

low-income populations residing within a 50-mi (80-km) radius of PINGP 1 and 2. This area of 

impact is consistent with the impact analysis for public and occupational health and safety, 

which also considers the radiological effects on populations located within a 50-mi (80-km) 

radius of the plant. The PIIC is located immediately north and adjacent to the NSP property 

within 1-mi (1.6-km) of PINGP 1 and 2. Because of its proximity to the plant and the uniqueness 

of the community, the NRC acknowledges that there is the potential for the PIIC to be

disproportionately affected by the continued operation of PINGP 1 and 2. However, as 

discussed in the previous sections of Chapter 4 of this SEIS, the analyses of impacts for all 

resource areas (e.g., land, air, water, ecology, human health, and socioeconomics), with the 

one exception of historic and archaeological (cultural) resources, indicated that the impact from 

license renewal would be SMALL. As discussed in Section 4.9.6, the MODERATE finding of 

impacts on historic and archaeological resources is based on the extensive amount of cultural 

resources located on the PINGP site of concern to the PIIC and the high potential for additional 

resources to be discovered on the site. However, given the applicant’s proposed mitigation 

strategies, as outlined in Section 4.9.6, the staff believes that adequate measures are in place 

to address the potential impacts to historic and archaeological resources at PINGP.
Environmental Impacts of Operation

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Figure 4-1 Prairie 

Island Indian 

Community Trust Land 

Boundary 

Source PIIC 2009
Environmental Impacts of Operation

4-45

Figure 4-2. Minority Block Groups 

with a 50-mi (80 km) radius of 

PINGP 1 and 2.

Source: NMC 2008
Environmental Impacts of Operation

4-46

Figure 4-3. Low-income Block 

Groups with a 50-mi (80 km) 

radius of PINGP 1 and 2.

Source: NMC 2008
Environmental Impacts of Operation

4-47

Further, Chapter 5 of this SEIS discusses the environmental impacts from postulated accidents 

that might occur during the period of extended operation for PINGP 1 and 2, which include 

design basis accidents. The Commission has generically determined that impacts associated 

with such accidents are SMALL because the plants were designed to successfully withstand 

design basis accidents. 

In addition, Chapter 3 of this SEIS discusses the environmental justice impacts of refurbishment 

activities at PINGP 1 and 2. As discussed, NSP has indicated that PINGP, Unit 2, steam 

generators would be replaced prior to the license renewal term. NSP estimates that steam 

generator replacement would require a one-time increase in the number of refueling outage 

workers for up to 80 days at PINGP 1 and 2 site (NMC 2008). NRC staff has concluded that 

such an increase in the workforce could have a disproportionate effect on the PIIC. However, 

impacts are of short duration, and are not expected to be high. 

Therefore, based on the overall findings discussed in Chapters 3, 4, and 5 of this SEIS, and a 

further examination to see if any of the resource impacts could present a unique adverse impact

to an affected population, the staff concludes that there would be no disproportionately high and 

adverse impacts to the PIIC or any other minority and low-income populations from the 

continued operation of PINGP 1 and 2 during the license renewal period.

As part of addressing environmental justice associated with license renewal, the NRC staff also 

analyzed the risk of radiological exposure through the consumption patterns of special pathway 

receptors, including subsistence consumption of fish, native vegetation, surface waters, 

sediments, and local produce; absorption of contaminants in sediments through the skin; and 

inhalation of plant materials. As discussed below, the special pathway receptors analysis is 

important to the environmental justice analysis because consumption patterns may reflect the 

traditional or cultural practices of minority and low-income populations in the area.

Section 4-4 of Executive Order 12898 (1994) directs Federal agencies, whenever practical and 

appropriate, to collect and analyze information on the consumption patterns of populations that

rely principally on fish and/or wildlife for subsistence and to communicate the risks of these 

consumption patterns to the public. In this SEIS, NRC considered whether there were any 

means for minority or low-income populations to be disproportionately affected by examining 

impacts to American Indian, Hispanic, and other traditional lifestyle special pathway receptors. 

Special pathways that took into account the levels of contaminants in native vegetation, crops, 

soils and sediments, surface water, fish, and game animals on or near PINGP 1 and 2 were 

considered.

Subsistence Consumption of Fish and Wildlife

NSP has an ongoing comprehensive Radiological Environmental Monitoring Program (REMP) 

at PINGP 1 and 2 to assess the impact of site operations on the environment. To assess the 

impact of the plant on the environment, the radiological monitoring program at PINGP 1 and 2 

uses indicator-control sampling. Samples are collected at nearby indicator locations downwind 

and downstream from the plant and at distant control locations upwind and upstream from the 

plant. A plant effect would be indicated if the radiation level at an indicator location was 

significantly larger than at the control location. The difference would also have to be greater 

than could be accounted for by typical fluctuations in radiation levels arising from other 

naturally-occurring sources.

Samples are collected from the aquatic and terrestrial pathways in the vicinity of PINGP

1 and 2. The aquatic pathways include fish, Mississippi River surface water, ground water, and 

sediment. The terrestrial pathways include airborne particulates, milk, and food product garden 

(leaf) vegetation, and direct radiation. During 2007, analyses performed on collected samples 
Environmental Impacts of Operation

4-48

of environmental media showed no significant or measurable radiological impact from PINGP 1 

and 2 site operations (NMC 2008b).

Aquatic sampling in the vicinity of PINGP 1 and 2 consists of semi-annual upstream and 

downstream collections of fish, periphyton (algae) or invertebrates, and bottom sediments. 

Shoreline sediment is collected semi-annually from one location. All samples are analyzed for 

gamma-emitting isotopes. River water is collected weekly at two locations, one upstream of the 

plant and one downstream. Monthly composites are analyzed for gamma-emitting isotopes. 

Quarterly composites are analyzed for tritium. Drinking water is collected weekly from the City 

of Red Wing well. Monthly composites are analyzed for gross beta, iodine-131, and gammaemitting isotopes. Quarterly composites are analyzed for tritium (NMC 2008b).

Fish were collected in May and October 2007, and analyzed for gamma emitting isotopes. Only 

naturally-occurring potassium-40 was detected, and there was no significant difference between 

upstream and downstream results. There was no indication of an effect from plant operations 

(NMC 2008b).

Tritium activity was below the lower level of detection in all drinking water samples taken from 

the City of Red Wing well, and no measurable tritium activity was detected in river water. Well 

water data for 2007 showed no radiological effects from plant operation (NMC 2008b).

Upstream and downstream recreational area shoreline sediments were sampled and analyzed 

for isotopes. With the exception of naturally occurring potassium-40, all gamma-emitting 

isotopes were below their respective detection limits. There was no indication of a plant effect 

(NMC 2008b).

According to PINGP 1 and 2 REMP, milk samples are collected monthly from six farms (five 

indicator and one control) and analyzed for iodine-131 and gamma-emitting isotopes. The milk 

is collected biweekly during the growing season (May - October), when milk animals may be on 

pasture. Green leafy vegetables (cabbage) are collected annually and analyzed for gammaemitting isotopes, including iodine-131. Corn is collected annually only if fields are irrigated with 

river water and analyzed for gamma-emitting isotopes. Well water and ground water are 

collected quarterly from four locations near the plant and analyzed for tritium and gammaemitting isotopes (NMC 2008b).

Iodine-131 and cesium-137 results were below the lower levels of detection in all milk samples. 

No other isotopes, except naturally-occurring potassium-40, were detected. The milk sampling 

data for 2007 is consistent with previous results and show no radiological effects from plant 

operation (NMC 2008b).

Three samples of broadleaf vegetation, cabbage leaves, were collected and analyzed for 

gamma-emitting isotopes, including iodine-131. With the exception of naturally-occurring 

potassium-40, all other isotopes were below their respective detection limits. There was no 

indication of a plant effect (NMC 2008b).

The results of the 2007 REMP demonstrate that the routine operation at PINGP 1 and 2 had no 

significant or measurable radiological impact on the environment. No elevated radiation levels 

were detected in the offsite environment as a result of plant operations and the storage of 

radioactive waste. The results of the REMP continue to demonstrate that the operation of 

PINGP 1 and 2 did not result in a significant measurable dose to a member of the general 

population or adversely impact the environment as a result of radiological effluents. The REMP 

continues to demonstrate that the dose to a member of the public from the operation of PINGP 

1 and 2 remains significantly below the federally required dose limits specified in 10 CFR 20, 

10 CFR 72, and 40 CFR 190.
Environmental Impacts of Operation

4-49

The Minnesota Department of Health (MDH), Radioactive Materials Unit in the Indoor 

Environments and Radiation Section monitors environmental radioactivity in Minnesota. 

Minnesota has maintained a radioactivity monitoring program since 1953. The MDH Radiation 

Control Unit currently maintains off-site environmental radiation monitoring programs around 

two nuclear power plants in Minnesota including PINGP 1 and 2.

Each year, MDH’s Radiation Control Unit collects dosimetry, air, river water, milk, food crop, and 

sediment samples in the vicinity of PINGP 1 and 2. Samples of apples and cow feed were 

collected by MDH in the vicinity of PINGP 1 and 2 from 2004 through 2006. MDH found no 

reactor-related radioisotopes in milk and food crop samples collected from 2004 through 2006 

(MDH Undated).

Based on recent monitoring results, concentrations of contaminants in native leafy vegetation, 

soils and sediments, surface water, and fish in areas surrounding PINGP 1 and 2 have been 

quite low (at or near the threshold of detection) and seldom above background levels. 

Consequently, no disproportionately high and adverse human health impacts would be 

expected in special pathway receptor populations in the region as a result of subsistence 

consumption of fish and wildlife.

The Prairie Island Indian Community’s Analysis of Environmental Justice

As discussed in Chapter 1, the PIIC is a Cooperating Agency for developing four areas of the 

PINGP 1 and 2 SEIS: historic and archaeological resources, socioeconomics, land use, and 

environmental justice. While these four areas are important to the Tribe, a tenet of Dakota 

culture is the belief that all things are related, “Mitakuye Oyasin,” and that one cannot separate 

one aspect of the environment from another. Mitakuye Oyasin, literally translated, means “to all 

my relations” or “we are all related.” Mitakuye Oyasin is a prayer, an acknowledgement that 

honors the sacredness of all people and of all life. In other words, the community’s health and 

well-being and culture are dependent upon the health of the natural environment—the water, 

the fish, the birds, the air, the plants, cultural sites, that are all interrelated as part of an 

ecosystem that is Prairie Island. 

The following discussion is provided by the PIIC (PIIC 2011).

Most members of the Prairie Island Indian Community believe that PINGP 1 and 

2 was built at its location because, at that time, the Tribe was in no position to 

fight it. In the late 1960s members of the tribe were quite poor and totally 

disenfranchised. The City of Red Wing fully supported the $200 million project, 

as the city would benefit tremendously from it. The city quickly annexed the-then 

NSP land (exclusive of the Prairie Island Indian Community) so that PINGP 1 and 

2 would become part of its tax base. Jobs were promised, but very few Tribal 

members have ever worked at PINGP 1 and 2.

PINGP 1 and 2 were built right next to the Tribe’s land. This land was acquired 

for the Prairie Island Indian Community by the United States government for the 

common benefit of all tribal members, in perpetuity. This was the only land the 

tribe had, the land promised to them by the Federal government, the land that 

would allow the Prairie Island Indian Community to maintain its traditions and 

culture. If members started leaving, how could the Prairie Island Indian 

Community continue to function as an Indian tribe?

The Tribal Council believes that the impacts to Tribal members are 

disproportionately high and adverse. That is, the Tribe assumes all of the risks 

associated with the operation of PINGP 1 and 2, including the Independent Spent 

Fuel Storage Installation (ISFSI) and the high-voltage transmission lines, and 
Environmental Impacts of Operation

4-50

receives virtually no benefit. The Prairie Island Indian Community is subjected to 

a number of impacts that have a potential integrated and cumulative effect:

Due to the Prairie Island Indian Community’s close proximity to PINGP 1 and 2 

(within 0.5 mi [0.8 km]), Tribal members believe that they are at an increased risk 

for health effects (such as increased cancer vulnerability). The Tribal Council 

believes that the health of tribal members has not been adequately studied. 

Human health impacts

Members of the Prairie Island Indian Community may have exposure pathways 

(water, food, air) that may be different from the typical or “average” consumer, 

thereby placing the tribal consumer at a greater risk. For example, many tribal 

members consume native plants for traditional purposes (direct consumption, 

medicines, teas, ceremonies) that are not typically part of the Radiological 

Environmental Monitoring Program (REMP). Many of our Tribal members have 

been living on Prairie Island since the plant went on-line. Tribal members 

typically do not move in and out of the community. We are concerned about the 

human health effects from 60 years of low-level exposure, as many of our tribal 

members already have compromised health.

The annual REMP reports and Radioactive Effluent Reports are insufficient to 

establish baselines for radiological effluent releases, exposure pathways, and 

dose estimates. Consequently, the analysis of the cumulative and integrated 

impacts on the Tribe, its members and its environment caused by the PINGP’s 

operation is deficient.

The following paragraph is from the National Academy of Sciences Institute of 

Health, Toward Environmental Justice: Research, Education, and Health Policy 

Needs

“The premise of environmental justice is that communities with high 

concentrations of racial or ethnic minorities or low-income families are 

disproportionately exposed to a variety of environmental burdens and hazards. 

Of particular interest for this report is the specific claim that such exposures 

produce adverse health outcomes that are also borne disproportionately by these 

populations. An assessment of baseline data is therefore essential to 

ascertaining the relative role of environmental exposure in determining the health 

of a population.” 

(National Academy Press 1999), p. 11. 

Just one of the radioactive nuclides released by the PINGP, tritium, can be 

analyzed as a tracer for all radioactive emissions. Based on available 

information, annual liquid tritium emissions at PINGP have steadily increased 

during the 35 years of plant operation by approximately 1.2 Ci per year, with a 

peak liquid tritium emission of 800 Ci in 2006 (2006 PINGP Annual Radioactive 

Effluent Report).

Tritium has also been found in the Tribe’s drinking water. In the late-1980 

through early-1990 time frame, above-normal background levels of tritium were 

detected in wells around PINGP 1 and 2. Although the detected levels of tritium 

were below the EPA standard of 20,000 picocuries per liter (pCi/L), the range 

detected (1,300 – 1,500pCi/L) was above what was detected in other wells (300 

– 400 pCi/L). At that time, all community members were utilizing individual wells. 

In response, the Community developed its current central water system in 1992, 

which utilizes a deep well (500 ft [150 m]). The detected tritium levels are below 
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the EPA drinking water standard of 20,000 pCi/L. The BEIR VII 2006 on 

radiation health effects, however, states that the Linear-No-Threshold standard 

should apply to chronic low dose exposure for potential cause of cancer and 

other radiation-induced diseases.

Review and analysis of PINGP’s Annual Radioactive Effluent Reports reveals the results 

of the ongoing efforts to monitor tritium, including disturbing spikes and fluctuations. For 

example, the 2006 Annual Radioactive Effluent Report (May 2007) disclosed tested 

tritium levels for the year in Well P-10 fluctuating from a low of 432 pCi/L to a peak of 

3,773 pCi/L in September 2006. The 2008 Annual Radioactive Effluent Report (May 

2009) showed that there were abnormal releases of tritium from the turbine building 

sump water discharge in July of 2008. As well, there seem to be corresponding 

increases in tritium detected in nearby (on-site) monitoring wells (2008 PINGP REMP 

Report). The detected level in July 2008 sample (at well P-10) was 2,060 pCi/L, when 

most other samples were <19 to 112 pCi/L; one sample contained 412 pCi/L. The 

abnormal spikes and fluctuations have not been satisfactorily explained, and the 

problem of tritium entering the ground water does not seem to have been resolved. 

Most recently, after an apparent decline in tritium levels around the plant, there was an 

unexplained spike in well P-10 (2980 pCi/L) in October 2010, approximately 50 times 

higher than the lowest most recently recorded level (58 pCi/l in March 2008). We have 

yet to receive a satisfactory answer as to why this occurred. Most troubling is the fact 

that NSP downplayed the findings as being “slightly elevated” and “well within normal 

fluctuations” of well P-10. As we approach the Spring melt and face the threat of historic 

flooding this year, the fact that the October 2010 tritium levels were significantly elevated 

following fall flooding is of great concern to the Community. We remain concerned that 

there is some correlation between high water levels (river and/or ground water) and 

elevated tritium levels. What has been done to ascertain whether there is any such 

correlation? Has the NRC reviewed the hydrology study prepared by NSP? Has the 

NRC reviewed the number, location, and detection capabilities of specific monitoring 

wells in light of NSP’s hydrology study? Is the NSP hydrology study sufficient? Is a 

more detailed, ongoing study required? Particularly given the apparent link between 

higher ground water levels and elevated tritium levels, the PIIC believes more 

comprehensive analysis is warranted. 

[NRC note: Environmental monitoring and tritium monitoring is discussed in Section 

4.8.1.]

Radiological releases from PINGP 1 and 2 and gamma radiation from the ISFSI 

are a concern to tribal members. Tribal members reside within 600 yds (550 m) 

of the PINGP 1 and 2 site. The Tribal Council is concerned about the health 

impacts from chronic exposure to low levels of radiation. Moreover, the 

proposed extended power uprate for PINGP 1 and 2 is expected to increase 

radiological releases by 10 percent. 

Subsequent to the release of the draft SEIS, the NRC announced that it had asked the 

National Academies of Science to perform a state-of-the art cancer risk study for 

populations surrounding nuclear power plants. This, in our view, raises important 

questions about the current study (done on 1990—20 years ago), upon which the NRC 

relies. The 1990 study evaluated mortality rates around nuclear powers. The NRC-NAS 

study will, among other things, evaluate cancer types and endpoints (incidence AND 

mortality), exposure pathways, various demographic data, and completeness and 

availability of data. To us, it makes no sense to rely on a twenty-year old study when the 

results of a state-of-the-art study will be available soon. We hope that the NRC either
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incorporates this updated cancer risk analysis in its review of this application or takes a 

retrospective look at power plant license renewals once this study is complete and the 

findings are made public.

Most tribal members believe that the spent nuclear fuel stored at PINGP 1 and 2 will 

never leave. Each day the “temporary” waste storage at PINGP 1 and 2 becomes more 

permanent. It is expected that up to 98 casks will be in use at PINGP 1 and 2, once the 

plant is decommissioned. Furthermore, under the revised waste confidence rule, the 98 

casks could conceivably be on Prairie Island until 2094 (60 years after cessation of 

operations). The NRC has not completed an environmental impact study evaluating the 

environmental and health consequences of long-term on-site storage of spent nuclear 

fuel. Indeed, the initial Environmental Assessment (EA) for the PINGP’s ISFSI was for a 

twenty-year period and the scope of the EA was not as broad as an EIS. Given the fact 

that the US government has all but abandoned Yucca Mountain (and wants to start the 

process anew), the 60-year time-period may not be enough. 

In 2005, we commissioned a public health study (conducted by the University of 

Minnesota), which documented that many of our youth experience increased 

levels of stress and anxiety because of health and safety fears related to the 

power plant. These are the same youth who will be our future leaders, the 

people with whom future NSP and NRC representatives will be working over the 

re-licensing period (McGovern, et al. 2006). We do not believe that children in 

any other communities worry about whether they will have a home to go to, if an 

accident were to occur. 

There are a number of homes within 100 ft (30 m) of the north-south 345 Kv 

transmission lines coming from PINGP 1 and 2. The lines are located on the 

east side of Edoka Street and the homes are located on the west side of Edoka 

Street. We understand that there is no consensus among scientists whether the 

electromagnetic energy emanating from the power lines would have a 

measurable human health impact. Some studies suggest exposure to EMF’s 

increases the risk for certain diseases.

Since there is no scientific consensus on whether human health is compromised, 

however, the Tribe believes that there is NO assurance that there are NO 

adverse health effects (i.e., chronic health effects, increased risks to cancer).

There have been accidents or events at PINGP 1 and 2 that have undermined 

our confidence in plant operations. In 1979, there was an accident at PINGP 1 

and 2 which released radioactive gas into the atmosphere. The cause of the 

accident was a rupture of a 1-in (2.54-cm) tube in Unit 1’s steam generator. The 

accident happened at 2:30 in the afternoon; no one from the Community was 

notified of the event nor told to shelter in place. It was not until community 

members noticed workers from the PINGP 1 and 2 site leaving the island, or 

later, watching the news, did anyone from the tribe know about the event.

After NSP loaded its first dry cask (after a very controversial and protracted State 

approval process) in the spring of 1995, the cask was left dangling over the spent 

fuel pool for several hours because of a malfunctioning crane. In addition, a 

Notice of Violation (NOV) was issued to NSP by the NRC because of problems 

with the manufacturing of the first casks.

In 2006, several outage workers were unexpectedly exposed to radiation. This 

was not reported to the media or anyone else. A journalist with one of the local 
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papers spotted the notice of the event on the NRC’s website. The Governor of 

Minnesota had not been informed of the event and learned about it through the 

media. In fact, the Tribal Council President and the Governor were at the same 

meeting when the news broke.

Most recently, the NRC has identified declining human performance as 

substantive cross cutting issue at the PINGP 1 and 2. This was noted by the 

NRC during the May 2009 Performance Assessment meeting and the September 

1, 2009 Mid-Cycle Performance Review letter. That the PINGP is also in the 

NRC’s Regulatory Response Column instead of the Licensee Response column 

is also cause for concern. These recent developments are sending us a 

troubling signal about future performance at the PINGP. 

These recent developments only serve to heighten existing concerns regarding 

the future performance and safety at the PINGP 1 and 2. At a time when Xcel is 

seeking approval from the NRC to extend the operation of the PINGP 1 and 2 

another 20 years, and also seeking approval from the Minnesota Public Utilities 

Commission to increase the output of PINGP 1 and 2 by 10%, the declining 

human performance finding is especially disconcerting. The public, and 

especially PINGP's closest neighbors, have significant concerns about the 

operation of PINGP's aging systems and equipment at increased temperatures, 

pressures, stresses and tolerances for an additional 20 years when human 

performance is declining.

As discussed above, the Prairie Island Indian Community bears the greatest risk, 

yet receives virtually no benefit from the operation of PINGP 1 and 2. As 

discussed in Chapter 2, the tribe signed an agreement with NSP in 2003, but the 

amount of funding received by the Tribe pales in comparison to the amount that 

has been provided to the City of Red Wing or Goodhue County, via taxes, since 

PINGP 1 and 2 went on-line.

Socioeconomic impacts

The Tribe has spent substantial amounts of money in legal and consultant fees in 

order to protect its interests and participate in various NSP proceedings at either 

the State or Federal level. There is no other governmental entity (e.g., City of 

Red Wing, Goodhue County, or the State of Minnesota) that participates in these 

proceedings at the same level as the Tribe. This is money that could be used for 

other community purposes; the Tribe believes that this impact must be 

considered.

There is only one primary access route (Sturgeon Lake Road) to and from the 

reservation. Twenty to thirty trains (and their hazardous commodities) and 

maintenance equipment (and crews) cross this intersection daily and 

occasionally block this only access road for up to 30 minutes. Many people are 

fearful that, in the event of a radiological emergency, tribal members would be 

trapped on the island.

As discussed in Chapter 3, there will be traffic impacts to the Community during the 

refurbishment period. NSP will hire as many as 750 additional workers for PINGP 1 and 

2, Unit 2, steam generator replacement project. The NRC staff has determined that the 

Prairie Island Indian Community will be disproportionately impacted by the project, 

because of the Community’s proximity to the PINGP 1 and 2 site. A short duration 

doesn’t minimize the impact to the community.
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The tribe has also had to develop its own radiological emergency preparedness 

(REP) program, with little outside financial assistance. As mentioned previously, 

the tribe has only recently begun to receive limited funding from NSP for REP 

planning, but it can only be used for training, travel, and supplies. The tribe 

covers salary and related costs.

Most members of the Community do not consume fish from the Mississippi River 

(Sturgeon Lake) because of pollution concerns (either from PINGP 1 and 2 or 

from other upstream dischargers). There are tribal members who hunt on tribal 

lands, but to the best of our knowledge, there are no longer any subsistencelevel consumers.

Subsistence Consumption of Fish and Wildlife

In addition, the tribe does not have any information pertaining to wildlife or game 

sampling or testing conducted by state agencies either before or after the plant 

was constructed.

In the past, the tribe has collaborated with the US Fish and Wildlife Service 

(USFWS) and the US Environmental Protection Agency (US EPA) to collect and 

test Sturgeon Lake fish and turtle samples for heavy metals, PCB’s and 

radionuclides.

Because of the aforementioned impacts, the PIIC believes that environmental 

and human health impacts to the PIIC from the relicensing of PINGP 1 and 2 are 

disproportionately high and adverse. Further, the PIIC believes that these issues 

over the 20 year extended operating period . 

As previously stated, the views presented in the sections above represent the different analyses 

used by the NRC staff and PIIC in addressing environmental justice. The NRC staff based its 

determination on, among other considerations, the individual impact analyses discussed in 

Chapter 4 of this DSEIS, particularly regarding Radiological Impacts (Section 4.8.1), 

Electromagnetic Fields (Sections 4.8.4), Socioeconomics (Section 4.9), and Historic and 

Archeological Resources (Section 4.9.6) to conclude that there exists no disproportionate high 

and adverse impacts to the PIIC or any other minority and low-income populations from the 

continued operation of PINGP 1 and 2 during the license renewal period. 

Environmental Justice Summary

4.10 Evaluation of New and Potentially Significant Information

New and significant information is (1) information that identifies a significant environmental issue 

not covered in the GEIS and codified in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, or 

(2) information that was not considered in the analyses summarized in the GEIS and that leads 

to an impact finding that is different from the finding presented in the GEIS and codified in 

10 CFR Part 51.

In preparing to submit its application to renew the PINGP 1 and 2 operating license, NSP 

developed a process to ensure that information not addressed in or available during the GEIS

evaluation regarding the environmental impacts of license renewal for PINGP 1 and 2 would be 

properly reviewed before submitting the ER, and to ensure that such new and potentially 

significant information related to renewal of the operating license for PINGP 1 and 2 would be 

identified, reviewed, and assessed during the period of NRC review. NSP reviewed the 

Category 1 issues that appear in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, to verify 

that the conclusions of the GEIS remained valid with respect to PINGP 1 and 2. This review 
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was performed by personnel from PINGP 1 and 2 and its support organization who were familiar 

with NEPA issues and the scientific disciplines involved in the preparation of a license renewal 

ER.

The NRC staff also has a process for identifying new and significant information. That process is 

described in detail in NUREG-1555, Supplement 1, Standard Review Plans for Environmental 

Reviews for Nuclear Power Plants, Supplement 1: Operating License Renewal (NRC 2000). 

The search for new information includes (1) review of an applicant’s ER and the process for 

discovering and evaluating the significance of new information; (2) review of records of public 

comments; (3) review of environmental quality standards and regulations; (4) coordination with 

Federal, state, and local environmental protection and resource agencies; and (5) review of the 

technical literature. New information discovered by the NRC staff is evaluated for significance 

using the criteria set forth in the GEIS. For Category 1 issues where new and significant

information is identified, reconsideration of the conclusions for those issues is limited in scope to 

the assessment of the relevant new and significant information; the scope of the assessment 

does not include other facets of the issue that are not affected by the new information.

The NRC staff has not identified any new and significant information on environmental issues 

listed in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, related to the operation of PINGP 

1 and 2 during the period of license renewal. The NRC staff also determined that information 

provided during the public comment period did not identify any new issues that require sitespecific assessment. The NRC staff reviewed the discussion of environmental impacts in the 

GEIS (NRC 1996) and conducted its own independent review (including the public scoping

meetings held in July 2008) to identify new and significant information.

4.11 Cumulative Impacts

The NRC staff considered potential cumulative impacts in the environmental analysis of 

continued operation of PINGP 1 and 2. For the purposes of this analysis, past actions are those 

related to the resources at the time of the power plant licensing and construction, present 

actions are those related to the resources at the time of current operation of the power plant, 

and future actions are considered to be those that are reasonably foreseeable through the end 

of plant operation including the period of extended operation. Therefore, the analysis considers 

potential impacts through the end of the current license terms as well as the 20-year renewal 

license term. The geographic area over which past, present, and future actions would occur is 

dependent on the type of action considered and is described below for each impact area.

The impacts of the proposed action, as described in Sections 4.1–4.9, are combined with other 

past, present, and reasonably foreseeable future actions regardless of what agency (Federal or 

non-Federal) or person undertakes such other actions. Actions which NSP has expressed an 

interest in pursuing are the license renewal of the independent spent fuel storage installation 

(ISFSI), expanding the number of spent fuel casks stored at the ISFSI, and a power uprate 

increase. Each of these actions requires that an application and environmental report be 

submitted to the NRC for review and approval of the proposed action. While there have been a 

number of pre-meetings to discuss these proposed actions, no applications have yet been 

submitted to the NRC for any of these projects. Without the specific technical information 

available for the proposed actions, staff is not able to perform a comprehensive environmental 

assessment for aquatic and water resources at this time. Qualitative evaluations in the areas of

human health, socioeconomics and cultural resources are included in the section of the SESI. 

Once the applications, with its environmental report, are submitted to the NRC, staff will 

conduct a thorough assessment of both safety and the impact to the environmental impact will 

be conducted and documented.
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4.11.1 Cumulative Impacts on Aquatic and Water Resources

This section addresses past, present, and future actions that together could result in adverse 

cumulative impacts to aquatic and water resources, including water use, water quality, shoreline 

and river conditions, fish and shellfish populations, and invasive species. For the purposes of 

this analysis, the geographic area considered includes the section of the river adjacent to 

PINGP 1 and 2, Pool 3, as well as Pools 2 and 4, which lie upstream and downstream of PINGP 

1 and 2, respectively.

The character and nature of the Upper Mississippi River was significantly and permanently 

changed by the construction of the Lock and Dam system in the 1930s to achieve 9-ft (3-m) 

navigation channels. The operation and continued maintenance involved with this system 

continues to affect the aquatic and water resources and alters sedimentation and resuspension 

of sediments; bottom type; flow and channelization; season patterns of flow that cue many 

biological processes; habitat diversity that provides areas for fish to spawn, rest, reproduce, 

feed, and grow; fish movements and migrations; and distribution of mussels and other aquatic 

resources. USACE continues to undertake projects that have both negative and positive effects 

on the ecology and hydrology of the Mississippi River.

As mentioned previously in Section 2.1.7.3, nitrogen enrichment is an important water quality 

issue in the upper Mississippi River. The influx of nitrogen from the Mississippi into the Gulf of 

Mexico creates a zone of decreased dissolved oxygen (hypoxia), and the Minnesota area 

contributes an estimated five to six percent of that nitrogen (EPA 2006).

A 2000 study (Stark et al. 2000) found that water quality in the upper Mississippi River is 

primarily influenced by agricultural and urban pesticides and fertilizers, wastewater treatment 

facility discharges, agricultural and urban runoff, stream modifications and artificial drainage 

routes, loss of riparian cover, and contamination from precipitation. Fertilizer and agricultural 

animal waste in particular are thought to be major nitrogen contributors to the Mississippi. Stark 

et al. (2000) also indicated that the main influences on ground water contamination are 

pesticides and fertilizers, urban contaminants, and naturally occurring radon gas. The study also 

highlighted the influence of confining units and water depth. Because the aquifer utilized at 

PINGP 1 and 2 is shallow and largely confined from the main aquifer used by both the Prairie 

Island Indian Community (PIIC) and the city of Red Wing, Stark et al. (2000) concluded that 

cross contamination interaction between these two water sources should be minimal.

The MPCA developed a Basin Plan for the Upper Mississippi to reduce river pollution (MPCA 

2008). The plan includes best management practices to reduce nitrogen and phosphorus 

discharges into the river. It also includes several local water quality studies, the largest of which 

are the National Water Quality Assessment Program in the Upper Mississippi River Basin and 

the USACE Upper Mississippi River Reconnaissance Study. The purpose of these water quality 

studies is to gather more information about the pollution problems in the Upper Mississippi so 

action can be taken to solve some of the problems (MPCA 2000). The MPCA also directs large 

water quality studies by the Minnesota River Basin Data Center (MRBDC). In 2000, the MRBDC 

concluded that the Upper Mississippi is severely impaired by high concentrations of both 

nutrients and sediment (MRBDC 2000). Efforts are underway to consider regulations that would 

improve water and sediment quality and reduce hypoxia in the Mississippi River and its 

discharge in the Gulf of Mexico. For example, the Upper Mississippi River Basin Association 

(2007) Water Quality Task Force is investigating sediment-related water quality criteria for the 

Upper Mississippi River, and EPA is considering a petition for rulemaking to replace narrative 

water quality criteria for nutrients in the Mississippi River Basin with numerical criteria (EPA 

2006). These efforts could have a positive effect on cumulative impact.
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PINGP 1 and 2 are located next to the PIIC. Based on information gathered during the site visit, 

the PIIC has a water treatment plant onsite that appears to discharge to the Mississippi River. 

The NPDES permit for the PIIC water treatment plant is not issued by MPCA but by the EPA. 

The community also has a large marina that brings a high frequency of boat traffic to the area. 

The increase in recreational boat traffic over the past few decades has contributed to increased 

erosion on the bottom of the river. Some small islands that used to exist near PINGP 1 and 2

are now almost completely submerged. The PIIC frequently dredges the main channel of 

Sturgeon Lake in order to maintain a navigable water depth for the marina traffic. Such dredging 

may disturb or destroy benthic communities.

PINGP 1 and 2 are located along Sturgeon Lake, a side slough connected to Navigation Pool 3, 

which is created by the upstream Lock and Dam 3. In late 2007, the USACE drafted a proposal 

to improve the quality of the water and emergent aquatic vegetation disturbed by the high 

elevations of water created by Lock and Dam 3. The project plans to use a seasonal summer 

drawdown of the water elevations in Sturgeon Lake. The hydrologic goal of the project is to 

improve water quality by way of sediment consolidation, reducing fetch, improving water clarity, 

and reducing nitrogen levels. The drawdown would also return the hydrologic cycle to a more 

natural state to induce the growth of aquatic vegetation. Based on information gathered at the 

site audit, including the observation that the pool elevation drop is not severe enough to 

significantly reduce the flow of the river at PINGP 1 and 2, the NRC believes the implementation 

of this project is unlikely to hinder water intake operations at PINGP 1 and 2, and would be 

beneficial to the water and aquatic resources of the area. (USACE 2007)

Pool 4, which is located downstream of PINGP 1 and 2, contains Lake Pepin. The USACE 

monitor ice coverage in the area. Along with other contributing factors, thermal effluent from 

PINGP 1 and 2 could in part be responsible for the deterioration of the ice cover in Lake Pepin.

NSP has indicated that they are planning to submit an application for a power uprate in the 

future, which could increase the amount of thermal effluent. In a letter to the Minnesota 

Department of Commerce, MNDNR expressed concern that, unless appropriate measures are 

taken, the thermal plume could have an increased negative effect on the ice cover of Lake 

Pepin (MNDNR 2008a). NRC assumes that changes in ice cover would impact biological 

communities. If in the future NSP does move forward with a power uprate application, the 

potential impacts associated with that action would be addressed by the NRC at that time.

The spread of an invasive species, the zebra mussel (Dreissena polymorpha), throughout the 

Mississippi River has had a devastating impact on native mussel populations in the area. As

discussed in Section 2.2.7 and 4.7.1, the FWS, the USACE, and the Mussel Coordination Team 

are engaged in a relocation project to aid in the recovery of the endangered Higgins eye 

pearlymussel. One of the relocation sites is in Pool 3, just half a mile upstream of the cooling 

water intake structure of PINGP 1 and 2. As of 2005, the project has reported “good recovery” in 

Pool 3 (Mussel Coordination Team 2005).

The NRC staff concludes that the minimal impacts of the continued operation of PINGP 1 and 2 

to aquatic and water resources would not contribute to an overall decline in the current condition 

of these resources. However the impacts of other past, present, and future actions, including 

dredging by the PIIC, water quality issues arising from agricultural and urban runoff, and most 

notably, the creation of the Lock and Dam system have had and will continue to have a 

significant impact on the Upper Mississippi River, including Pools 2, 3, and 4; therefore, the 

cumulative impacts on these resources are MODERATE to LARGE. 
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4.11.2 Cumulative Impacts on Terrestrial Resources

This section addresses past, present, and future actions that could result in adverse cumulative 

impacts to terrestrial resources, including wildlife populations, upland habitats, wetlands, 

riparian zones, invasive species, protected species, and land use. For purposes of this analysis, 

the geographic area considered in the evaluation includes the PINGP 1 and 2 site and in-scope 

transmission line ROWs.

Approximately 60 ac (24 ha) of the 578 ac (234 ha) of land on the PINGP 1 and 2 site are 

developed and maintained for operation of PINGP 1 and 2 (NMC 2008). The site is situated on 

a floodplain on the western bank of the Mississippi River. Before PINGP 1 and 2 were

constructed, the majority of the site’s land was cultivated with some interspersed lowland forests 

and swamp areas near the site (AEC 1973). Goodhue County, in which PINGP 1 and 2 are

located, and Dakota County, through which the Blue Lake and Red Rock 2 transmission lines 

travel, are mostly rural, and soybeans, corn, oats, and hay are the predominately cultivated 

crops (NMC 2008).

Construction of the transmission lines maintained by NSP and Great River Energy for PINGP 1 

and 2 resulted in subsequent changes to the wildlife and plant species present within the vicinity 

of PINGP 1 and 2. Due to the fragmentation of previously contiguous forested and swamp 

areas, edge effects such as changes in light, wind, and temperature, changes in abundance and 

distribution of interior species, reduced habitat ranges for certain species, and an increased 

susceptibility to invasive species may have occurred in these areas. ROW maintenance has 

likely had past impacts and is likely to have present and future impacts on the terrestrial habitat. 

These impacts may include bioaccumulation of chemicals, prevention of the natural 

successional stages of the surrounding vegetative communities in and around the ROWs, and 

increase in abundance of edge species, a decrease in abundance of interior species, and an 

increase in invasive species populations.

Protected terrestrial species, which are discussed in Section 2.2.7, are not expected to be 

adversely affected due to future actions during the renewal term. Numerous wildlife refuges and 

scientific and natural areas are located in the vicinity of the PINGP 1 and 2 site, and these will 

continue to provide habitat to protected species and other wildlife. Habitat restoration efforts by 

the FWS in the Upper Mississippi River National Wildlife and Fish Refuge will support 

improvement of riverine habitat and native grass prairie.

The USACE, in conjunction with the MNDNR, Wisconsin Department of Natural Resources 

(WDNR), and other Federal and state agencies are considering a 1 to 2 ft (0.3 to 0.6 m) 

drawdown of Pool 3 for the purposes of improving aquatic habitat along this portion of the 

Mississippi River (WDNR 2008). Drawdown of Pool 3 would expose more of the small islands 

between the side and main channels of the river, which would create more riparian and wetland 

habitat in these areas.

The Treasure Island Resort and Casino is located about 1 mi (1.6 km) upstream of PINGP 1 

and 2. The resort and casino is owned by the PIIC and includes a hotel, casino, and marina. 

Additionally, the PIIC operate a wastewater treatment facility. Initial construction of the resort 

and casino resulted in the loss of natural terrestrial habitat and fragmentation of previously 

contiguous areas of prairie grasslands. Increased boating traffic in Pool 3 of the Mississippi 

River as a result of the marina may cause increased erosion to riparian and wetland habitat 

along the shorelines. The wastewater treatment plant discharges to the Mississippi River. Those 

discharges may have current and future impacts on the surrounding vegetation, wetlands, and 

wildlife. Bioaccumulation and food web transfer of chemicals throughout the terrestrial 
Environmental Impacts of Operation

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environment also poses a threat to these habitats, as well as to riparian zones and wildlife 

species.

The cities of Minneapolis and St. Paul lie 39 and 32 mi (63 and 52 km), respectively, northwest 

of PINGP 1 and 2 (NMC 2008). Development of suburban housing and numerous interstate 

roads in northern Goodhue County in the 1970s and 1980s spurred subsequent commercial and 

industrial growth of the area in the 1990s (NMC 2008). Continued development of this area in 

the future may result in additional runoff from roads and impervious surfaces, development 

adjacent to wetlands and riparian zones, and an increase in waste releases, all of which could 

have future impacts on the terrestrial habitat.

The NRC staff examined the cumulative effects of forest fragmentation, the spread of invasive 

species, impacts to protected species, effects of neighboring facilities, and continued land 

development in the Minnepolis-St.Paul area. The NRC staff concludes that the minimal 

terrestrial impacts on the continued PINGP 1 and 2 operations would not contribute to the 

overall decline in the condition of terrestrial resources. The NRC staff believes that the 

cumulative impacts of other and future actions during the term of license renewal on terrestrial 

habitat and associated species, when added to past, present, and reasonably foreseeable 

future actions, would be SMALL.

4.11.3 Cumulative Human Health Impacts

The radiological dose limits for protection of the public and workers have been developed by the 

EPA and NRC to address the cumulative impact of acute and long-term exposure to radiation 

and radioactive material. These dose limits are codified in 40 CFR Part 190 and 

10 CFR Part 20. For the purpose of this analysis, the area within a 50-mi (80-km) radius of the 

PINGP 1 and 2 site is considered. There are no other nuclear power plants within

50 mi (80 km) of PINGP 1 and 2. EPA regulations, 40 CFR Part 190, limit the dose to members 

of the public from all sources in the nuclear fuel cycle, including nuclear power plants, fuel 

fabrication facilities, waste disposal facilities, storage of spent nuclear fuel in dry casks at an 

ISFSI, and transportation of fuel and waste. The REMP conducted by NMC in the vicinity of the 

PINGP 1 and 2 site measures radiation and radioactive materials from all sources; PINGP 1 and 

2, the ISFSI, refueling and maintenance outages; therefore, the monitoring program measures 

cumulative radiological impacts.

Radiological data for the 5-year period from 2003 to 2007 and the most recent reports for 2009 

were reviewed as part of the staff’s cumulative radiological impacts assessment. In Section 

4.8.1 of this SEIS, the staff concluded that impacts of radiation exposure from operation of 

PINGP 1 and 2 during the renewal term to the public and workers (occupational) are SMALL. 

The NRC and the State of Minnesota would regulate any future actions in the vicinity of the 

PINGP 1 and 2 site that could contribute to cumulative radiological impacts.

The replacement of the Unit 2 steam generators during the period of extended operation is not 

expected to result in a significant increase in the projected dose to a member of the public from 

the discharge of radioactive liquid and gaseous effluents than from those effluents discharged 

during normal plant operations because of the use of the radioactive waste treatment systems. 

The replacement of the PINGP Unit 2 steam generators is likely to result in a small increase in 

the amount of solid radioactive waste generated. This is based on a temporary increase in the 

number of personnel working at the plant which will result in more solid waste being generated 

during the outage and any other associated related work. During an outage of this type, there 

will be an increased use of protective clothing, safety equipment, increased use of filters, and a 

general increase in generation of debris that will have to be disposed of as radioactive waste.
Environmental Impacts of Operation

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However, the increased volume is expected to be short-termed and within the range of solid 

waste that can be safely handled by PINGP 1 and 2 during the period of extended operation. 

The cumulative radiological impact from a potential power increase is not expected to result in a 

significant impact to human health because, as part of the NRC’s license amendment process, 

the staff will perform a thorough evaluation of the safety, radiological, and environmental issues 

associated with the proposed power increase to verify that all regulatory requirements are met. 

This includes a specific environmental assessment prepared by the staff on the potential 

environmental impacts associated with the proposed power increase. The cumulative dose 

from PINGP 1 and 2 is required to remain within the NRC’s radiation dose limits in 

10 CFR Part 20, the ALARA dose criteria in Appendix I to 10 CFR Part 50, and EPA’s 

40 CFR Part 190 dose standards.

Therefore, based on the staff’s review of the radiological effluent and environmental monitoring 

data and the expected continued compliance with Federal radiation protection standards, the 

staff concludes that the cumulative radiological impacts on human health from continued 

operations of PINGP 1 and 2, including replacement of steam generators, its ISFSI, and a 

possible power uprate during the renewal term would be SMALL.

The NRC staff determined that the electric-field-induced currents from the PINGP 1 and 2 

transmission lines are below the National Electric Safety Code recommendations for preventing 

electric shock from induced currents. Therefore, the PINGP 1 and 2 transmission lines do not 

appreciably affect the overall potential for electric shock from induced currents within the 

analysis area. With respect to chronic effects of electromagnetic fields, the staff considers the 

GEIS finding of “not applicable” to be appropriate in regard to PINGP 1 and 2’s transmission 

lines that are within the scope of license renewal. Therefore, the NRC staff has determined that 

the cumulative impacts of the continued operation of the PINGP 1 and 2 transmission lines 

would be SMALL.

4.11.4 Cumulative Socioeconomic Impacts

This section addresses socioeconomic factors that have the potential to be directly or indirectly 

affected by changes in operations at PINGP 1 and 2 in addition to the aggregate effects of other 

past, present, and reasonably foreseeable future actions. The primary geographic area of 

interest considered in this cumulative analysis is Goodhue and Dakota Counties in Minnesota 

and Pierce County in Wisconsin where approximately 83 percent of PINGP 1 and 2 employees 

reside. This area is where the economy, tax base and infrastructure would most likely be 

affected since PINGP 1 and 2 workers and their families reside, spend their income, and use 

their benefits within these counties.

Socioeconomics

As discussed in Section 4.9.4 of this SEIS, continued operation of PINGP 1 and 2 during the 

license renewal term would have no impact on socioeconomic conditions in the region beyond 

what is currently being experienced. Since NSP has no plans to hire additional workers during 

the license renewal term, overall expenditures and employment levels at PINGP 1 and 2 would 

remain relatively constant with no additional demand for permanent housing, public utilities, and 

public services. In addition, since employment levels and the tax payments would not change, 

there would be no population or tax revenue-related land use impacts Based on this and other 

information presented in Chapter 4 of this SEIS, there would be no additional contributory effect 

on socioeconomic conditions in the future from the continued operation of PINGP 1 and 2 

during the license renewal term beyond what is already being experienced.
Environmental Impacts of Operation

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NSP indicated in their environmental report that the PINGP 1 and 2, Unit 2, steam generators 

would be replaced prior to the license renewal term. NSP estimates that steam generator 

replacement would require a one-time increase in the number of refueling outage workers for up 

to 80 days at PINGP 1 and 2 (NMC 2008). These additional workers would create a one-time 

short-term increase in the demand for temporary (rental) housing, and increased use of public 

water and sewer services, and transportation impacts on access roads in the immediate vicinity 

of PINGP 1 and 2. Given the short amount of time needed to replace the steam generators, the 

additional number of refueling outage workers and truck material deliveries needed to support 

this one-time replacement of the PINGP 1 and 2, Unit 2, steam generators could have a 

temporary cumulative effect on socioeconomic conditions in the vicinity of the nuclear plant. 

However, there would be no long-term cumulative socioeconomic impacts from the PINGP 1 

and 2, Unit 2, steam generator replacement in the region.

NSP has notified the NRC that it intends to increase the licensed core thermal power level of 

PINGP 1 and 2. EPU-related plant modifications would occur during two or more refueling 

outages. Potential socioeconomic impacts from the EPU include temporary increases in the 

size of the workforce at PINGP 1 and 2 and associated increased demand for public services, 

housing, and increased traffic in the region. The EPU could also increase tax payments due to 

increased power generation and assessed value.

Extended Power Uprate (EPU)

Additional workers would be on site to implement the EPU in addition to the 925 refueling 

outage workers. The volume of construction and worker vehicles on roads and the demand for 

rental housing and other commercial and public services would increase beyond what is 

normally experienced during refueling outages at PINGP. Due to the short duration of EPUrelated plant modification activities, there would be little or no noticeable long-term effect on 

sales and income tax revenues generated by temporary workers residing in Goodhue, Dakota, 

or Pierce counties. The contributory cumulative effect on socioeconomic conditions of this 

action could be SMALL to MODERATE in the immediate vicinity of PINGP 1 and 2 during the 

two outages.

NSP has announced plans to expand an existing Independent Spent Fuel Storage Installation 

(ISFSI) for storage of spent fuel at PINGP 1 and 2. Potential socioeconomic impacts from ISFSI 

expansion include temporary increases in the size of the workforce at PINGP and associated 

increased demand for public services, housing, and increased traffic in the region. The ISFSI 

could also increase tax payments due to increased income and assessed value.

Independent Spent Fuel Storage Installation (ISFSI)

The volume of construction and worker vehicles on roads and the demand for rental housing 

and other commercial and public services would increase during the expansion of the ISFSI. 

The contributory cumulative effect on socioeconomic conditions of this action could be SMALL 

to MODERATE in the immediate vicinity of the PINGP plant site.

Any ground disturbing activities in support of PINGP 1 and 2 during the license renewal term in 

addition to offsite ground disturbing activities could result in the cumulative loss of 

archaeological resources on Prairie Island. Archaeological resources are non-renewable; 

therefore, the loss of archaeological resources is cumulative. The continued operation of 

PINGP 1 and 2 during the license renewal term has the potential to impact archaeological 

resources.

Historic and Archaeological Resources
Environmental Impacts of Operation

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As discussed in Section 4.9, continued operation of PINGP 1 and 2 during the license renewal 

term would have a SMALL to MODERATE impact on archaeological resources at the PINGP 1 

and 2 site. NSP has no plans to alter the PINGP 1 and 2 site for license renewal. Any land 

disturbing activities would be carried out under corporate procedures. Should plans change, 

further consultation would be initiated by NSP with the NRC, MHS, OSA, BIA, and the PIIC. 

NSP revised its corporate procedures to ensure the protection of archaeological resources at 

PINGP 1 and 2, along with detailed instructions to follow in the case of accidental discovery of 

archaeological resources (Xcel 2009). NSP is currently seeking comment from the MHS, BIA, 

OSA, and the PIIC on its revised procedures. Because impacts to important resources from the 

continued operation of PINGP 1 and 2 are SMALL to MODERATE, the cumulative 

environmental impacts to archaeological resources would be SMALL to MODERATE.

Prior to any ground-disturbing activity, NSP would consider the potential discovery and impact 

on archaeological resources according to their corporate procedures in consultation with the 

MNHS and the PIIC. NSP would consult with a qualified archaeologist prior to conducting any 

ground-disturbing activity in any area designated as undisturbed and in any disturbed area that 

is described as potentially containing archaeological resources (as determined by the Phase I 

Reconnaissance Field Survey discussed in New Commitment Number 38). The NRC has also 

considered the effects of the reasonably foreseeable extended power uprate of PINGP 1 and 2 

and ISFSI expansion and concluded that impacts from these projects on historic and 

archaeological resources would be SMALL. Therefore, NRC concludes that the contributory 

effect of these reasonably foreseeable actions to the cumulative impact on historic and 

archaeological resources and the continued operation of PINGP 1 and 2 during the license 

renewal period would be SMALL to MODERATE.

4.11.5 Cumulative Environmental Justice Impacts

The environmental justice cumulative impact analysis assesses the potential for 

disproportionately high and adverse human health and environmental effects on minority and 

low-income populations that could result from past, present, and reasonably foreseeable future 

actions including PINGP 1 and 2 operations during the renewal term. Adverse health effects 

are measured in terms of the risk and rate of fatal or nonfatal adverse impacts on human health. 

Disproportionately high and adverse human health effects occur when the risk or rate of 

exposure to an environmental hazard for a minority or low-income population is significant and 

exceeds the risk or exposure rate for the general population or for another appropriate 

comparison group. Disproportionately high environmental effects refer to impacts or risk of 

impact on the natural or physical environment in a minority or low-income community that are 

significant and appreciably exceeds the environmental impact on the larger community. Such 

effects may include biological, cultural, economic, or social impacts. Some of these potential 

effects have been identified in resource areas presented in Chapter 4 of this SEIS. Minority and 

low-income populations and the PIIC are subsets of the general public residing in the area and 

all would exposed to the same hazards generated from PINGP 1 and 2 operations. As 

previously discussed in this chapter, the impact from license renewal for most resource areas 

(e.g., land, air, water, ecology, and human health) would be SMALL.

As discussed in Section 4.9.7 of this SEIS, there would be no disproportionately high and 

adverse impacts to minority and low-income populations from the continued operation of PINGP 

1 and 2 during the license renewal term. Since NSP has no plans to hire additional non-outage 

workers during the license renewal term, employment levels at PINGP 1 and 2 would remain 

relatively constant with no additional demand for housing or increased traffic. Based on this 

information and the analysis of human health and environmental impacts presented in Chapters 

4 and 5, it is not likely there would be any disproportionately high and adverse contributory 
Environmental Impacts of Operation

4-63

effect on minority and low-income populations from the continued operation of PINGP 1 and 2 

during the license renewal term.

Potential impacts to minority and low-income populations from EPU-related plant modifications 

and ISFSI expansion at PINGP would mostly consist of environmental and socioeconomic 

effects (e.g., noise, dust, traffic, employment, and housing impacts). Radiation doses from plant 

operations after the implementation of the EPU are expected to remain at current levels, and, 

along with the ISFSI expansion and dry-cask storage of spent nuclear fuel, would be well within 

regulatory limits.

Noise and dust impacts during EPU-related plant modifications and ISFSI expansion would be 

short-term and limited to onsite activities at PINGP. Minority and low-income populations and 

members of the PIIC residing along site access roads would experience increased commuter 

vehicle traffic during shift changes. In addition, increased demand for rental housing during the 

refueling outages and EPU-related plant modifications and ISFSI expansion at the PINGP plant 

site could disproportionately affect low-income populations. However, due to the short duration 

of the EPU-related plant modifications and ISFSI expansion and the availability of rental housing 

in the three county ROI, impacts to minority and low-income populations would be short-term 

and limited. According to American Community Survey 2009 estimates, there were over 8,000 

vacant housing units in Goodhue, Dakota, and Pierce counties.

Based on this information and the analysis of human health and environmental impacts 

presented in this SEIS, the EPU and ISFSI expansion at PINGP would not have any long-term 

cumulative disproportionately high and adverse human health and environmental operational 

effects on minority and low-income populations residing in the vicinity of PINGP 1 and 2.

Nevertheless, due to its close proximity to PINGP 1 and 2, the PIIC could be disproportionately 

affected during refueling outages by the additional number of workers needed to implement 

EPU-related plant modifications and ISFSI expansion activities. The effects would primarily 

consist of increased transportation and noise impacts during shift changes. However, these 

impacts are of short duration and are not expected to be high. As previously discussed for the 

PINGP Unit 2 steam generator replacement, NSPM has expressed a willingness to work with 

the PIIC to coordinate and implement appropriate measures to mitigate transportation impacts. 

Mitigation measures may include using NSPM’s private access road for heavy truck traffic, 

using local law enforcement to control traffic during PINGP shift changes, and staggering the 

work schedule, if necessary.

The following information is the PIIC’s analysis of cumulative impacts associated with 

environmental justice.

As discussed above, the Prairie Island Indian Community believes that it will be 

impacted disproportionately and adversely over the twenty year license renewal 

period. No other community is as close to PINGP 1 and 2 as the Prairie Island 

Indian Community. No other community is impacted, in as many ways, as the 

Prairie Island Indian Community. Furthermore, these impacts will have a 

cumulative environmental justice impact on our community.

No other minority community or federally-recognized Indian tribe is impacted the 

way the Prairie Island Indian Community is.

No other community (within a 50-mi [80-km] radius) is so close to a nuclear 

power plant and a nuclear waste storage facility.
Environmental Impacts of Operation

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No other community is subjected to chronic radiological releases from PINGP 1 

and 2 and gamma radiation from the ISFS I. This will also increase once the 

anticipated extended power uprate is approved by the NRC and NSP is allowed 

to expand the ISFSI to 64 casks and eventually to 98 casks once PINGP 1 and 2 

is decommissioned. For many of our members, their exposure to low levels of 

radiation is for their entire lifetime.

Our youth are worrying about the effects of an accident on their community and 

their futures; no other community has documented the same concerns. 

High-voltage power lines from the PINGP 1 and 2 site are located immediately 

next to several of our homes. 

No other community has tritium leaching into its groundwater from 

PINGP 1 and 2.

Our community would be devastated by an accident—our homeland would be 

gone, our culture would be decimated, our means of providing services to tribal 

members would be gone, and our tribal members’ primary income would be 

gone. No other community faces this undesirable prospect.

No other community (within the 50-mi [80-km] radius) has the emergency 

planning concerns the tribe does (i.e., only one access road).

No other community participates in state or federal 

proceedings (using its own resources) to the extent that the Prairie Island Indian 

Community does.

As we stated earlier, we believe that all things are related and that you cannot 

affect one thing without affecting another. We know there are impacts to our 

community from the continued operation of the PINGP 1 and 2 and the ISFSI. 

We do not look at the ISFSI as separate from the reactor. We do not look at 

accidents as credible or non-credible, we believe that an accident could happen 

and it will devastate our community. We know that NSP plans to amend its 

operating license to operate at a higher level and that this action (and its impacts 

are considered to be out of scope for this SEIS). Nevertheless, we know that 

there will be an increase in radiological and thermal emissions resulting from the 

uprate. We know tritium is in our groundwater and that we did not ask for it to be 

there. We know that our youth feel that they have an uncertain future (because of 

the PINGP 1 and 2) and that affects the future of the tribe.

Taken together, we believe that these issues have an integrated and cumulative 

negative impact on our community that will continue impact our community well 

after the twenty-year extended operating period. 

4.11.6 Summary of Cumulative Impacts

We considered the potential impacts resulting from operation of PINGP 1 and 2 during the 

period of extended operation and other past, present, and future actions in the vicinity of PINGP 

1 and 2. The impacts to individual resource areas range from SMALL to LARGE. The 

preliminary determination is that the potential overall cumulative impacts resulting from PINGP 1 

and 2 operation during the period of extended operation would be SMALL to MODERATE.
Environmental Impacts of Operation

4-65

Table 4-13. Summary of Cumulative Impacts on Resources Areas

Resource Area Impact Discussion

Aquatic and Water 

Resources

MODERATE to 

LARGE

Impacts to aquatic resources from continued operation 

of PINGP 1 and 2 would have small impacts. Past

impacts to the Mississippi River, specifically creation of 

a Lock and Dam system have had significant impacts 

on the aquatic environment. Nutrient enrichment from 

agricultural and urban runoff, land development, and 

sedimentation, as well as dredging of the Sturgeon

Lake portion of the river by the PIIC, will also continue 

to affect water and aquatic resources. 

Terrestrial Resources SMALL ROW maintenance, invasive species, chemical 

discharges from nearby wastewater treatment plants, 

and development of neighboring areas have all 

impacted terrestrial habitat and species in the vicinity of 

PINGP 1 and 2, and would likely continue in the future.

Human Health SMALL The cumulative human health impacts of continued 

operation of PINGP 1 and 2 from radiation exposure to 

the public and electric-field-induced currents from the 

PINGP 1 and 2 transmission lines would be small. 

Socioeconomics MODERATE There would be MODERATE cumulative impacts to 

socioeconomics during the license renewal period, and 

no long-term cumulative impacts from refurbishment. 

There would be MODERATE cumulative impacts to 

historic and archaeological resources during the license 

renewal period. 

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5-1

5.0 ENVIRONMENTAL IMPACTS OF POSTULATED ACCIDENTS

This chapter describes the environmental impacts from postulated accidents that might occur 

during the period of extended operation. The term “accident” refers to any unintentional event 

outside the normal plant operational envelope that results in a release or the potential for 

release of radioactive materials into the environment. Two classes of postulated accidents are 

evaluated in NUREG-1437, Generic Environmental Impact Statement for License Renewal of 

Nuclear Power Plants (GEIS), and are listed in Table 5-1 below. These are design-basis 

accidents (DBAs) and severe accidents.

Table 5-1. Issues Related to Postulated Accidents. Two issues related to postulated 

accidents are evaluated under NEPA in the license renewal review, design-basis accidents and 

severe accidents.

Issues GEIS Sections Category

Design-basis accidents 5.3.2; 5.5.1 1

Severe accidents 5.3.3; 5.3.3.2; 

5.3.3.3; 5.3.3.4; 

5.3.3.5; 5.4; 5.5.2

2

5.1 Design Basis Accidents

In order to receive U.S. Nuclear Regulatory Commission (NRC) approval to operate a nuclear 

power facility, an applicant for an initial operating license must submit a safety analysis report 

(SAR) as part of its application. The SAR presents the design criteria and design information for 

the proposed reactor and comprehensive data on the proposed site. The SAR also discusses 

various hypothetical accident situations and the safety features that are provided to prevent and 

mitigate accidents. The NRC staff reviews the application to determine whether the plant design 

meets the Commission’s regulations and requirements and includes, in part, the nuclear plant 

design and its anticipated response to an accident.

DBAs are those accidents that both the licensee and the NRC staff evaluate to ensure that the 

plant can withstand normal and abnormal transients, and a broad spectrum of postulated 

accidents, without undue hazard to the health and safety of the public. A number of these 

postulated accidents are not expected to occur during the life of the plant, but are evaluated to 

establish the design basis for the preventative and mitigative safety systems of the facility. The 

acceptance criteria for DBAs are described in 10 Code of Federal Regulations (CFR) 50 and 

10 CFR 100.

The environmental impacts of DBAs are evaluated during the initial licensing process, and the 

ability of the plant to withstand these accidents is demonstrated to be acceptable before 

issuance of the operating license. The results of these evaluations are found in license 

documentation such as the applicant’s final safety analysis report (FSAR), the safety evaluation 

report (SER), the final environmental impact statement (FEIS), and Section 5.1 of this 

supplemental environmental impact statement (SEIS). A licensee is required to maintain the 

acceptable design and performance criteria throughout the life of the plant, including any 

extended-life operation. The consequences for these events are evaluated for the hypothetical 

maximum exposed individual; accordingly, changes in the plant environment will not affect these 

evaluations. Because of the requirements that continuous acceptability of the consequences 

and aging management programs be in effect for the period of extended operation, the 
Postulated Accidents

5-2

environmental impacts as calculated for DBAs should not differ significantly from initial licensing 

assessments over the life of the plant, including the period of extended operation. Accordingly, 

the design of the plant relative to DBAs during the period of extended operation is considered to 

remain acceptable and the environmental impacts of those accidents were not examined further 

in the GEIS.

The Commission has determined that the environmental impacts of DBAs are of SMALL 

significance for all plants because the plants were designed to successfully withstand these 

accidents. Therefore, for the purposes of license renewal, DBAs are designated as a Category 1 

issue. The early resolution of the DBAs makes them a part of the current licensing basis of the 

plant; the current licensing basis of the plant is to be maintained by the licensee under its 

current license and, therefore, under the provisions of 10 CFR 54.30, is not subject to review 

under license renewal.

The NRC did not identify any new and significant information related to DBAs during the review 

of the applicant’s ER (NMC 2008), the staff’s site audit, the scoping process, or the evaluation of 

other available information. Therefore, there are no impacts related to these issues beyond 

those discussed in the GEIS.

5.2 Severe Accidents

Severe nuclear accidents are those that are more severe than DBAs because they could result 

in substantial damage to the reactor core, whether or not there are serious offsite

consequences. In the GEIS, the staff assessed the impacts of severe accidents during the 

license renewal period using the results of existing analyses and site-specific information to 

conservatively predict the environmental impacts of severe accidents for each plant during the 

renewal period.

Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, 

fires, and sabotage have not traditionally been discussed in quantitative terms in FESs and 

were not specifically considered for the Prairie Island Nuclear Generating Plant, Units 1 and 2, 

(PINGP 1 and 2) site in the GEIS. However, the GEIS did evaluate existing impact assessments 

performed by NRC and the industry at 44 nuclear plants in the United States and concluded that 

the risk from beyond design basis earthquakes at existing nuclear power plants is SMALL. The 

GEIS for license renewal performed a discretionary analysis of sabotage acts in connection with 

license renewal and concluded that the core damage and radiological release from such acts 

would be no worse than the damage and release expected from internally initiated events. In the 

GEIS, the Commission concludes that the risk from sabotage at existing nuclear power plants is 

small and additionally, that the risks from other external events are adequately addressed by a 

generic consideration of internally initiated severe accidents (NRC 1996).

Based on the information in the GEIS, the Commission found that

The probability weighted consequences of atmospheric releases, fallout onto 

open bodies of water, releases to ground water, and societal and economic 

impacts from severe accidents are small for all plants. However alternatives to 

mitigate severe accidents must be considered for all plants that have not 

considered such alternatives.

The NRC did not identify any new and significant information related to severe accidents during 

the review of the applicant’s ER (NMC 2008), the staff’s site audit, the scoping process, or the 

evaluation of other available information. Therefore, there are no impacts related to these issues 

beyond those discussed in the GEIS. However, in accordance with 10 CFR 51.53(c)(3)(ii)(L), 
Postulated Accidents

5-3

the NRC staff has reviewed severe accident mitigation alternatives (SAMAs) for PINGP 1 and 2. 

The results of the review are discussed in Section 5.3.

5.3 Severe Accident Mitigation Alternatives

10 CFR Section 51.53(c)(3)(ii)(L) requires that license renewal applicants consider alternatives 

to mitigate severe accidents if the staff has not previously evaluated SAMAs for the applicant's 

plant in an environmental impact statement (EIS) or related supplement or in an environmental 

assessment. The purpose of this consideration is to ensure that plant changes (i.e., hardware, 

procedures, and training) with the potential for improving severe accident safety performance 

are identified and evaluated. SAMAs have not been previously considered for PINGP 1 and 2; 

therefore, the remainder of Chapter 5 addresses those alternatives.

5.3.1 Introduction

This section presents a summary of the SAMA evaluation for PINGP 1 and 2 conducted by 

Northern States Power Company (NSP) and the NRC staff's review of that evaluation. The NRC 

staff performed its review with contract assistance from Information Systems Laboratories, Inc.

The NRC staff=s review is available in full in Appendix G; the SAMA evaluation is available in full 

in NSP=s ER.

The SAMA evaluation for PINGP 1 and 2 was conducted with a four-step approach. In the first 

step, NSP quantified the level of risk associated with potential reactor accidents using the 

plant-specific probabilistic risk assessment (PRA) and other risk models. 

In the second step, NSP examined the major risk contributors and identified possible ways 

(SAMAs) of reducing that risk. Common ways of reducing risk are changes to components, 

systems, procedures, and training. NSP identified 25 potential SAMAs for each unit. NSP 

performed an initial screening in which they eliminated SAMAs that are not applicable to PINGP 

1 and 2 due to design differences, have already been implemented at PINGP 1 and 2, have no 

significant benefit or have benefits which have been achieved by other means, or require 

extensive changes that would involve implementation costs known to exceed any possible 

benefit. This screening reduced the list of potential SAMAs to nine for each unit.

In the third step, NSP estimated the benefits and the costs associated with each of the 

remaining SAMAs. Estimates were made of how much each SAMA could reduce risk. Those 

estimates were developed in terms of dollars in accordance with NRC guidance for performing 

regulatory analyses (NRC 1997). The cost of implementing the proposed SAMAs was also 

estimated.

Finally, in the fourth step, the costs and benefits of each of the remaining SAMAs were 

compared to determine whether the SAMA was cost-beneficial, meaning the benefits of the 

SAMA were greater than the cost (a positive cost-benefit). NSP concluded in its ER that several 

of the SAMAs evaluated are potentially cost-beneficial (NMC 2008). However, in response to 

NRC staff inquiries regarding the treatment of consequential steam generator tube rupture 

(SGTR) in the baseline PRA, the approach used to estimate uncertainty, and the consideration 

of lower cost alternatives, several additional potentially cost-beneficial SAMAs were identified 

(NSP 2009a and 2009b).

The potentially cost-beneficial SAMAs do not relate to adequately managing the effects of aging 

during the period of extended operation; therefore, they need not be implemented as part of 

license renewal pursuant to 10 CFR Part 54. NSP's SAMA analyses and the NRC's review are 

discussed in more detail below.
Postulated Accidents

5-4

5.3.2 Estimate of Risk

NSP submitted an assessment of SAMAs for PINGP 1 and 2 as part of the ER (NMC 2008).

This assessment was based on the most recent PINGP 1 and 2 PRA available at that time, a 

plant-specific offsite consequence analysis performed using the MELCOR Accident 

Consequence Code System 2 (MACCS2) computer program, and insights from the PINGP 1 

and 2 Individual Plant Examination (IPE) (NSP 1994) and Individual Plant Examination of 

External Events (IPEEE) (NSP 1998).

The baseline core damage frequency (CDF) for the purpose of the SAMA evaluation is 

approximately 9.79 x 10-6 per year for Unit 1 and 1.21 x 10-5 per year for Unit 2. The CDF values 

are based on the risk assessment for internally initiated events. NSP did not include the 

contributions from external events within the PINGP 1 and 2 risk estimates; however, it did 

account for the potential risk reduction benefits associated with external events by increasing 

the estimated benefits for internal events by a factor of two. The breakdown of CDF by initiating 

event for Units 1 and 2 is provided in Table 5-2.

Table 5-2. PINGP 1 and 2 Core Damage Frequency

Unit 1 Unit 2

Initiating Event CDF 

(per year)

% Contribution 

to CDF

CDF 

(per year)

% Contribution 

to CDF

Small LOCA 4.8 x 10-6 49 5.4 x 10-6 45

Loss of Cooling Water 1.8 x 10-6 18 1.8 x 10-6 15

Loss of Offsite Power 1.0 x 10-6 11 1.2 x 10-6 10

Loss of Main Feedwater 3.9 x 10-7 4 4.1 x 10-7 3

Medium LOCA 3.4 x 10-7 3 5.4 x 10-7 4

Loss of Component Cooling 

Water 

2.9 x 10-7 3 2.9 x 10-7 2

Large LOCA 2.8 x 10-7 3 3.1 x 10-7 3

Internal Flooding 2.4 x 10-7 2 2.4 x 10-7 2

Normal Transient 2.4 x 10-7 2 2.8 x 10-7 2

Steam Generator Tube Rupture 

(SGTR)

1.9 x 10-7 2 1.1 x 10-6 9

Loss of Train A DC 3.8 x 10-8 <1 4.0 x 10-7 3

Other 2.1 x 10-7 2 1.7 x 10-7 1

Total CDF (internal events) 9.79 x 10-6 100 1.21 x 10-5 100

As shown in Table 5-2, events initiated by small loss of coolant accident (LOCA), loss of cooling 

water and loss of offsite power are the dominant contributors to internal event CDF for each 

unit. The differences in the CDF contributions result largely from several differences between 

the two PINGP 1 and 2 units.

NSP estimated the dose from an accident to the population within 80 km (50 mi) of the PINGP 1 

and 2 site to be approximately 0.0294 person-sievert (Sv) (2.94 person-rem) per year for Unit 1 

and 0.0843 person-Sv (8.43 person-rem) per year for Unit 2 (NMC 2008). The breakdown of the 

total population dose by containment release mode is summarized in Table 5-3. Releases due 
Postulated Accidents

5-5

to SGTR events, interfacing system loss-of-coolant accidents (ISLOCAs), and late containment 

failures dominate the population dose risk at PINGP 1 and 2.

Table 5-3. Breakdown of Population Dose by Containment Release Mode

Containment Release Modes

Unit 1 Unit 2

Population 

Dose

(personrem(a) 

per 

year)

Percent 

Contribu

tion

Population 

Dose

(personrem(a) 

per 

year)

Percent 

Contribu

tion

Intact 

Containment

Normal 

Leakage

0.01 0.4 0.01 0.2

Early Containment 

Failure

Over-pressure 

Failure

0.12 4.1 0.14 1.7

Isolation 

Failure

<0.01 0.1 <0.01 <0.1

Late Containment 

Failure

Basemat 

Failure

0.63 21.4 0.76 9.0

Over-pressure 

Failure

0.12 4.1 0.12 1.4

Containment 

Bypass

SGTR 1.32 44.9 6.66 79.0

ISLOCA 0.74 25.0 0.74 8.7

Total 2.94 100 8.43 100

The NRC staff has reviewed NSP's data and evaluation methods and concludes that the quality 

of the risk analyses is adequate to support an assessment of the risk reduction potential for 

candidate SAMAs. Accordingly, the staff based its assessment of offsite risk on the CDFs and 

offsite doses reported by NSP.

5.3.3 Potential Plant Improvements

Once the dominant contributors to plant risk were identified, NSP searched for ways to reduce 

that risk. In identifying and evaluating potential SAMAs, NSP considered insights from the plantspecific PRA, and SAMA analyses performed for other operating plants that have submitted 

license renewal applications. NSP identified 25 potential risk-reducing improvements (SAMAs) 

to plant components, systems, procedures and training.

NSP removed 16 SAMAs from further consideration because they are not applicable to PINGP 

1 and 2 due to design differences, have already been implemented at PINGP 1 and 2, have no 

significant benefit or have benefits which have been achieved by other means, or require 

extensive changes that would involve implementation costs known to exceed any possible 

benefit. A detailed cost-benefit analysis was performed for each of the nine remaining SAMAs.

The staff concludes that NSP used a systematic and comprehensive process for identifying 

potential plant improvements for PINGP 1 and 2, and that the set of potential plant 

improvements identified by NSP is reasonably comprehensive and, therefore, acceptable. 
Postulated Accidents

5-6

5.3.4 Evaluation of Risk Reduction and Costs of Improvements

NSP evaluated the risk-reduction potential of the remaining nine SAMAs. The SAMA 

evaluations were performed using realistic assumptions with some conservatism.

NSP estimated the costs of implementing the candidate SAMAs through the application of 

engineering judgment, use of other licensee’s estimates for similar improvements, and sitespecific cost estimates. The cost estimates conservatively did not include the cost of 

replacement power during extended outages required to implement the modifications, nor did 

they include contingency costs associated with unforeseen implementation obstacles.

The staff reviewed NSP=s bases for calculating the risk reduction for the various plant 

improvements and concludes that the rationale and assumptions for estimating risk reduction 

are reasonable and somewhat conservative (i.e., the estimated risk reduction is similar to or 

somewhat higher than what would actually be realized). Accordingly, the staff based its 

estimates of averted risk for the various SAMAs on NSP=s risk reduction estimates.

The staff reviewed the bases for the applicant=s cost estimates. For certain improvements, the 

staff also compared the cost estimates to estimates developed elsewhere for similar 

improvements, including estimates developed as part of other licensees= analyses of SAMAs for 

operating reactors and advanced light-water reactors. The staff found the cost estimates to be 

reasonable, and generally consistent with estimates provided in support of other plants=

analyses.

The staff concludes that the risk reduction and the cost estimates provided by NSP are sufficient 

and appropriate for use in the SAMA evaluation.

5.3.5 Cost-Benefit Comparison

The cost-benefit analysis performed by NSP was based primarily on NUREG/BR-0184 (NRC 

1997) and was executed consistent with this guidance. NUREG/BR-0058 has recently been 

revised to reflect the agency=s revised policy on discount rates. Revision 4 of NUREG/BR-0058 

states that two sets of estimates should be developed: one at 3 percent and one at 7 percent 

(NRC 2004). NSP provided both sets of estimates (NMC 2008).

In the baseline analysis contained in the ER (using a 3 percent discount rate), NSP identified 

one potentially cost-beneficial SAMA for Unit 1 and two potentially cost-beneficial SAMAs for 

Unit 2. The potentially cost-beneficial SAMAs are:

SAMA 9 (Unit 1 and Unit 2) – Implement procedure or plant modification to 

improve ventilation for safeguards equipment in the Screenhouse.

SAMA 22 (Unit 2 only) – Provide compressed air backup for instrument air to 

containment.

NSP performed additional analyses to evaluate the impact of parameter choices and 

uncertainties on the results of the SAMA assessment (NMC 2008). If the benefits are based on 

use of the 95th percentile CDF results rather than the point estimate for CDF (to account for 

uncertainties) one additional SAMA candidate was determined to be potentially cost-beneficial 

for Unit 1. This is SAMA 22, which had already been shown to be cost-beneficial for Unit 2.

As a result of additional analyses in response to NRC staff requests, NSP identified three 

additional potentially cost-beneficial SAMAs (NSP 2009a and 2009b):

SAMA 3 – provide alternate flow path from refueling water storage tank (RWST)

to charging pump suction (for Units 1 and 2)
Postulated Accidents

5-7

SAMA 19a – provide a reliable backup water source for replenishing the RWST 

(for Unit 2)

An unnumbered SAMA regarding purchase of a gagging device for closing a 

stuck-open steam generator safety valve in SGTR events (for Units 1 and 2)

In addition, NSP has indicated that as a result of an identified internal flood modeling limitation, 

two internal flood related enhancements previously identified in the IPE have also been entered 

into the Corrective Action Program for further evaluation after the PRA has been updated with 

improved methodology for modeling pipe breaks (NSP 2009b).

The staff concludes that, with the exception of the potentially cost-beneficial SAMAs discussed 

above, the costs of the SAMAs evaluated would be higher than the associated benefits.

5.3.6 Conclusions

The staff reviewed NSP’s analysis related to SAMAs and concluded that the methods used and 

the implementation of those methods were sound. The treatment of SAMA benefits and costs 

support the general conclusion that the SAMA evaluations performed by NSP are reasonable 

and sufficient for the license renewal submittal.

Based on its review of the SAMA analysis, the staff concurs with NSP=s identification of areas in 

which risk can be further reduced in a cost-beneficial manner through the implementation of all 

or a subset of potentially cost-beneficial SAMAs. Given the potential for cost-beneficial risk 

reduction, the staff considers that further evaluation of these SAMAs by NSP is warranted.

However, none of the potentially cost-beneficial SAMAs relate to adequately managing the 

effects of aging during the period of extended operation. Therefore, they need not be 

implemented as part of the license renewal pursuant to 10 CFR Part 54.

5.4 Environmental Justice Issues Related to Severe Accidents, as submitted by 

the PIIC

The following information is provided by the Prairie Island Indian Community (PIIC). The 

information below does not represent the opinion of the NRC staff.

The evaluation of severe accidents, within the environmental justice analysis is of 

paramount importance to the Prairie Island Indian Community. 

The Prairie Island Indian Community believes that the NRC, as part of its

environmental justice review, should evaluate the potential risk associated with 

accidents that may have a disproportionate impact on minority populations. The 

Prairie Island Indian Community is the closest community to the PINGP 1 and 2. 

This concept of risk includes the potential consequences of a reactor accident. 

Mitigation of severe accidents is an integral part of the NRC’s Severe Accident 

Mitigation Alternatives (SAMA) analysis. The Tribe does not believe, however, 

that the SAMA process can provide a realistic or acceptable treatment of the risk 

to the Tribe’s unique status as an Indian Tribe and minority Community. 

Therefore, the Tribe believes that the risk from an accident and mitigating 

measures must be specifically analyzed by the NRC as part of its Environmental 

Justice analysis. In the case of the continued operation of PINGP, the

consequences of an accident would have a disproportionate impact on the Tribe, 

given its close proximity to PINGP 1 and 2 and its unique identity as a federallyrecognized Indian tribe. 
Postulated Accidents

5-8

Members of our community and our ancestors have lived on Prairie Island for 

countless generations. There is also a unique relationship between our culture 

and this specific location. Prairie Island is our only home and the location of our 

business (which can only

If there was a severe reactor accident, 801 current tribal members would also 

lose a primary source of income and the Tribal government could no longer 

provide benefits or services to tribal members. Of course, non-Indians would be 

also be affected by severe accidents as well. Non-Indian residents in the region 

of the PINGP 1 and 2, however, could simply buy individual parcels of land 

outside the region in the event of contamination from a reactor accident. The 

Tribe, however, would face the daunting task of re-locating and re-establishing 

the entire tribal community (which includes an adequate land base that would 

meet the needs of tribal members). In addition, the Treasure Island Resort and 

Casino cannot be easily re-located. Federal laws and regulations govern not 

only how a Tribal gaming facility operates, but where a Tribal gaming facility can 

be located. Therefore this disproportionate impact on the Community would be 

high and adverse.

be located on our reservation), which is our primary

means of providing services (including income) to our community. Not all 

impacts to the tribe would be economic—if there was an accident at PINGP, our 

culture would be significantly impacted, if not decimated, as it is inextricably 

linked to this unique and irreplaceable resource called Prairie Island. 

Although NRC regulations reduce the probability of accidents, these high and 

adverse disproportionate impacts would still call for the implementation of 

mitigating measures to reduce, as much as practicable, the impacts on the Tribe. 

Such mitigating measures would include the requirement that NSP must 

implement all SAMAs found to be cost-beneficial, both age-related and non-age 

related. An appropriate finding of a high and adverse disproportionate impact on 

the PIIC, would also substantially enable the Tribe to begin a dialogue with 

appropriate entities of the Untitled States government to ensure that adequate 

replacement land would be provided to the Community. 

5.5 References

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NRC (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, Washington, D.C. 

ADAMS Nos. ML040690705 and ML040690738.

NRC (U.S. Nuclear Regulatory Commission). 1997. Regulatory Analysis Technical Evaluation 

Handbook. NUREG/BR-0184, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 2004. Regulatory Analysis Guidelines of the U.S. 

Nuclear Regulatory Commission. NUREG/BR-0058, Rev. 4, Washington, D.C

NSP (Northern States Power Company). 1994. Prairie Island Nuclear Generating Plant 

Individual Plant Examination (IPE), NSPLMI-94001, Rev. 0, March 1, 1994.
Postulated Accidents

5-9

NSP (Northern States Power Company). 1998. PINGP Individual Examination of External 

Events (IPEEE), NSPLMI-96001, Rev. 1, October 19, 1998.

NSP (Northern States Power Company – Minnesota). 2008. Letter from M. Wadley, Site Vice 

President, Northern States Power Company – Minnesota, to U.S. Nuclear Regulatory 

Commission. Subject: Response to NRC Request for Additional Information Dated October 23, 

2008 Regarding Application for Renewed Operating Licenses. November 21, 2008. ADAMS No. 

ML083370505.

NSP (Northern States Power Company – Minnesota). 2009a. Letter from M. Wadley, Site Vice 

President, Northern States Power Company – Minnesota, to U.S. Nuclear Regulatory 

Commission. Subject: Response to NRC Requests for Additional Information Dated December 

24, 2008 Regarding Application for Renewed Operating Licenses. January 23, 2009. ADAMS 

No. ML090260290.

NSP (Northern States Power Company – Minnesota). 2009b. Letter from M. Wadley, Site Vice 

President, Northern States Power Company – Minnesota, to U.S. Nuclear Regulatory 

Commission. Subject: Supplemental Information Regarding Application for Renewed Operating 

Licenses. March 4, 2009. ADAMS No. ML090690684.



6-1

6.0 ENVIRONMENTAL IMPACTS OF THE URANIUM FUEL CYCLE AND

SOLID WASTE MANAGEMENT

6.1 The Uranium Fuel Cycle

This chapter addresses issues related to the uranium fuel cycle and solid waste management 

during the period of extended operation. The uranium cycle includes uranium mining and 

milling, the production of uranium hexafluoride, isotopic enrichment, fuel fabrication, 

reprocessing of irradiated fuel, transportation of radioactive materials and management of lowlevel wastes and high-level wastes related to uranium fuel cycle activities. The generic potential 

impacts of the radiological and nonradiological environmental impacts of the uranium fuel cycle 

and transportation of nuclear fuel and wastes are described in detail in the Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) (NRC 

1996; 1999) based, in part, on the generic impacts provided in 10 CFR 51.51(b), Table S-3, 

“Table of Uranium Fuel Cycle Environmental Data,” and in 10 CFR 51.52(c), Table S-4, 

“Environmental Impact of Transportation of Fuel and Waste to and from One Light-WaterCooled Nuclear Power Reactor.” The GEIS also addresses the impacts from radon-222 and 

technetium-99.

No new and significant information related to the uranium fuel cycle was identified during the 

review of the Northern States Power Co. (NSP) environmental report (ER)( NMC 2008), the site 

audit, or the scoping process. Therefore, there are no impacts related to these issues beyond 

those discussed in the GEIS. For these category 1 issues, the GEIS concludes that the impacts 

are SMALL except for the collective offsite radiological impacts from the fuel cycle and from 

high-level waste and spent fuel disposal, which are site-specific, category 2 analysis.
Environmental Impacts of the Uranium Fuel Cycle 

6-2

Table 6-1. Issues Related to the Uranium Fuel Cycle and Solid Waste 

Management. There are nine generic issues related to the fuel cycle and waste 

management. There are no site-specific issues.

Issues GEIS Sections Category

Offsite radiological impacts (individual effects from other 

than the disposal of spent fuel and high-level waste)

6.1; 6.2.1; 6.2.2.1; 

6.2.2.3; 6.2.3; 

6.2.4; 6.6 1

Offsite radiological impacts (collective effects)

6.1; 6.2.2.1; 6.2.3; 

6.2.4; 6.6 1

Offsite radiological impacts (spent fuel and high-level 

waste disposal)

6.1; 6.2.2.1; 6.2.3; 

6.2.4; 6.6 1

Nonradiological impacts of the uranium fuel cycle

6.1; 6.2.2.6; 

6.2.2.7; 6.2.2.8; 

6.2.2.9; 6.2.3; 

6.2.4; 6.6 1

Low-level waste storage and disposal

6.1; 6.2.2.2;6.4.2; 

6.4.3; 6.4.3.1; 

6.4.3.2; 6.4.3.3; 

6.4.4; 6.4.4.1; 

6.4.4.2; 6.4.4.3; 

6.4.4.4; 6.4.4.5; 

6.4.4.5.1; 6.4.4.5.2; 

6.4.4.5.3; 6.4.4.5.4; 

6.4.4.6;6.6 1

Mixed waste storage and disposal

6.4.5.1; 6.4.5.2; 

6.4.5.3; 6.4.5.4; 

6.4.5.5; 6.4.5.6; 

6.4.5.6.1; 6.4.5.6.2; 

6.4.5.6.3; 6.4.5.6.4; 

6.6 1

Onsite spent fuel

6.1; 6.4.6; 6.4.6.1; 

6.4.6.2; 6.4.6.3; 

6.4.6.4; 6.4.6.5; 

6.4.6.6; 6.4.6.7; 6.6 1

Nonradiological waste

6.1; 6.5; 6.5.1; 

6.5.2; 6.5.3; 6.6 1

Transportation

6.1; 6.3.1; 6.3.2.3; 

6.3.3; 6.3.4; 6.6, 

Addendum 1 1

6.2 Greenhouse Gas Emissions

6.2.1 Introduction

The NRC staff received comments during the scoping period from individuals and groups 

regarding the impact of the proposed license renewal of PINGP 1 and 2 on the release of 

carbon dioxide (CO2) and other greenhouse gas (GHG) emissions relative to potential 
Environmental Impacts of the Uranium Fuel Cycle

6-3

alternative energy sources, including fossil fuels, renewable energy sources, and conservation 

programs.

6.2.2 PINGP 1 and 2

The NRC staff has not indentified any studies specifically addressing GHGs produced by 

PINGP 1 and 2 or their fuel cycles.

6.2.3 GEIS

The GEIS provided only qualitative discussion regarding the GHG impacts of the nuclear fuel 

cycle. In the analysis of potential alternatives to nuclear power plant relicensing, the GEIS 

referenced CO2 emissions as one of the substantial operating impacts associated with new 

coal-fired and oil-fired power plants, although no direct quantitative assessment of GHG 

emissions was presented. The GEIS also did not address GHG impacts of the nuclear fuel cycle 

relative to other potential alternatives, such as natural gas, renewable energy sources, or 

conservation programs.

6.2.4 Other Studies

Since the development of the GEIS, extensive further research into the relative volumes of 

GHGs emitted by nuclear and other electricity generating methods has been performed. In 

support of the analysis for this SEIS, the NRC staff performed a survey of the recent literature 

on the subject. Based on this survey, the NRC staff found that estimates and projections of the 

carbon footprint of the nuclear power lifecycle vary widely, and considerable debate exists 

regarding the relative impacts of nuclear and other electricity generation methods on GHG 

emissions. These recent studies take two different forms:

1) qualitative discussions of the potential use of nuclear power to address GHG 

emissions and global warming

2) technical analysis and quantitative estimates of the actual amount of GHGs 

generated by the nuclear fuel cycle

6.2.5 Qualitative

The qualitative studies primarily consist of broad, large-scale public policy or investment 

evaluations of whether an expansion of nuclear power is likely to be a technically, economically, 

and/or politically feasible means of achieving global GHG reductions. Examples of the studies

that the NRC staff identified during the subsequent literature search include the following:

• Studies conducted to evaluate whether investments in nuclear power in 

developing countries should be accepted as a flexibility mechanism to assist 

industrialized nations in achieving their GHG reduction goals under the Kyoto 

Protocols (Schneider 2000; IAEA 2000; NEA 2002; and NIRS/WISE 2005). 

Ultimately, the parties did not approve nuclear power as a component under 

the Clean Development Mechanism (CDM), but not because of concerns 

about GHGs from the nuclear fuel cycle (NEA 2002). Instead, it was 

eliminated from consideration for the CDM because it was not considered to 

meet the criterion of helping developing nations achieve sustainable 

development because of safety and waste disposal concerns (NEA 2002).
Environmental Impacts of the Uranium Fuel Cycle 

6-4

• Analyses developed to assist governments (including the U.S. Government) 

in making long-term investment and public policy decisions in nuclear power 

(Keepin 1988; Hagen et al. 2001; MIT 2003). 

Although the qualitative studies sometimes reference and critique the rationale contained in the 

existing quantitative estimates of GHGs produced by the nuclear fuel cycle, their conclusions 

generally rely heavily on discussions of other aspects of nuclear policy decisions and 

investment such as safety, cost, waste generation, and political acceptability. Therefore, these 

studies are not directly applicable to the evaluation of GHG emissions that will be associated 

with the proposed relicensing of PINGP 1 and 2.

6.2.6 Quantitative

A large number of technical studies, including calculations and estimates of the amount of 

GHGs emitted by nuclear and other power generation options, are available in the literature.

Examples of these studies include Mortimer (1990), Andseta et al. (1998), Spadaro (2000), 

Storm van Leeuwen and Smith (2005), Fritsche (2006), POST (2006), AEA (2006), Weisser 

(2006), Fthenakis and Kim (2007), and Dones (2007).

Comparison of the different studies is difficult because the assumptions and components of the 

lifecycles included within each study vary widely. Examples of differing assumptions that make 

comparability between the studies difficult include the following:

• the type of energy source that may be used to mine uranium deposits in the 

future

• the amount of reprocessing of nuclear fuel that will be performed in the future

• the type of energy source and process that might be used to enrich uranium 

in the future

• different calculations regarding the grade and volume of recoverable uranium 

deposits in the world

• different estimates regarding the GHG emissions associated with declining 

grades of recoverable coal, natural gas, and oil deposits

• the release of GHG gases other than CO2, including the conversion of the 

masses of these gases into grams of CO2 equivalents per kilowatt-hour (g 

Ceq /kWh)

• the technology to be used for future fossil fuel power systems, including 

cogeneration systems

• the projected capacity factors assumed for the different generation 

alternatives

• the different types of nuclear reactors used currently and in the projected 

future (light water reactor, pressurized-water reactor, Canadian deuteriumnatural uranium reactor, breeder)

In addition, studies are inconsistent in their application of full lifecycle analyses, including plant 

construction, decommissioning, and resource extraction (uranium ore, fossil fuel). For instance, 

Storm van Leeuwen and Smith (2005) present comparisons of GHG emissions from nuclear 

versus natural gas that incorporate GHG emissions associated with nuclear plant construction 

and decommissioning in the values used for comparison.
Environmental Impacts of the Uranium Fuel Cycle

6-5

In the case of the proposed PINGP 1 and 2 relicensing, the relicensing action will not involve 

additional GHG emissions associated with construction because the facility already exists. In 

addition, the proposed relicensing action will not involve additional GHG emissions associated 

with facility decommissioning, because that decommissioning must occur whether the facility is 

relicensed or not. Some emissions will occur as a result of construction associated with 

refurbishment activities; however, as discussed in Chapter 3 of this SEIS, these impacts are 

expected to be short-term and minimal. In many of these studies, the contribution of GHG 

emissions from facility construction and decommissioning cannot be separated from the other 

lifecycle GHG emissions that would be associated with PINGP 1 and 2 relicensing. Therefore, 

these studies overestimate the GHG emissions attributed to the proposed PINGP 1 and 2

relicensing action.

In an early study on the subject, Dr. Nigel Mortimer conducted an analysis of the GHG 

emissions resulting from the nuclear fuel cycle in 1990 (Mortimer 1990). In this study, Mortimer 

stressed that the GHG implications of the nuclear fuel cycle were substantially related to the ore 

grade of uranium that must be mined to support nuclear power generation. Using ore grades 

that were current as of 1990, this study concluded that nuclear power offered a dramatic 

reduction in GHG emissions over conventional coal-fired power plants over an estimated 

35-year lifecycle. The analysis estimated that a nuclear power plant would generate 230,000 

tons (209,000 metric tonnes [MT]) of CO2 over a 35-year life span, or about 3.9 percent of the 

5,912,000 tons (5,363,000 MT) that an equivalent coal-fired plant would generate (Mortimer 

1990). The study also projected that most of this 230,000 tons (209,000 MT) of CO2 resulted 

from the use of a coal-fired plant to perform uranium enrichment by gaseous diffusion, and that 

using nuclear power and alternative enrichment methods in the future could reduce the amount 

to 21,000 tons (19,000 MT) (Mortimer 1990). 

Mortimer’s study went on to demonstrate that the GHG impact of the nuclear fuel cycle would 

increase as the grade of uranium ore mined dropped, and that the net emissions of CO2 from 

the nuclear and coal-fired alternatives would become equal once uranium ore grades reached 

0.01-percent uranium oxide. However, Mortimer does not address differences in energy 

consumption from future extraction and enrichment methods, the potential for higher grade 

resource discovery, and technology improvements. Based on his cutoff ore grade and 

projections of ore reserves, Mortimer estimated GHG emissions of nuclear and natural gas 

generation would have the same emissions after a period of 23 years (Mortimer 1990). The 

analysis also compared GHG emissions associated with the nuclear fuel cycle with other 

electricity generation and efficiency options, including hydroelectric, wind, tidal power, and new 

types of insulation and lighting (but not including natural gas). The conclusion was that nuclear 

power had lower GHG emissions compared to coal, but that GHG emissions associated with the 

nuclear fuel cycle still exceeded those for renewable generation and conservation options 

(Mortimer 1990).

The Mortimer (1990) study is not presented here to support a definitive conclusion regarding 

whether nuclear energy produces fewer GHG emissions than other alternatives and similar 

discussions will not be presented in this SEIS for each of the available studies. Instead, the 

NRC staff presents the Mortimer (1990) study to provide an example of the types of 

considerations underlying the calculations and arguments presented by the various authors.

Almost every existing study has been critiqued, and its assumptions challenged, by later 

authors. Therefore, no single study has been selected to represent definitive results in this 

SEIS. Instead, the results from a variety of the studies are presented in Tables 6-2, 6-3, and 6-4 

to provide a weight-of-evidence argument comparing the relative GHG emissions resulting from 

the proposed PINGP 1 and 2 relicensing compared to the potential alternative use of coal-fired 

plants, natural gas-fired plants, and renewable energy sources.
Environmental Impacts of the Uranium Fuel Cycle 

6-6

6.2.7 Summary of Nuclear Greenhouse Gas Emissions Compared to Coal

Because coal is the fuel most commonly used to generate electricity in the U.S., and the burning 

of coal results in the largest emissions of GHGs for any of the likely alternatives to nuclear 

power, most of the available quantitative studies have focused on comparisons of the relative 

GHG emissions of nuclear to coal-fired generation. The quantitative estimates of the GHG 

emissions associated with the nuclear fuel cycle, as compared to an equivalent coal-fired plant, 

are presented in Table 6-2.

Table 6-2. Nuclear Greenhouse Gas Emissions Compared to Coal

Source GHG Emission Results

Mortimer 1990 Nuclear—230,000 tons CO2 

Coal—5,912,000 tons CO2

Note: Future GHG emissions from nuclear to increase because of declining 

ore grade

Andseta et al. 

1998

Nuclear energy produces 1.4 percent of the GHG emissions compared to 

coal.

Note: Future reprocessing and use of nuclear-generated electrical power in 

the mining and enrichment steps are likely to change the projections of 

earlier authors, such as Mortimer (1990).

Spadaro 2000 Nuclear—2.5 to 5.7 g Ceq/kWh 

Coal—264 to 357 g Ceq/kWh

Fritsche 2006 

(values estimated 

from graph in 

Figure 4)

Nuclear—33 g Ceq/kWh

Coal—950 g Ceq/kWh

POST 2006 

(Nuclear 

calculations from 

AEA 2006)

Nuclear—5 g Ceq/kWh

Coal—>1000 g Ceq/kWh

Note: Decrease of uranium ore grade to 0.03% would raise nuclear to 6.8 g 

Ceq /kWh. Future improved technology and carbon capture and storage 

could reduce coal-fired GHG emissions by 90 percent.

Weisser 2006 

(compilation of 

results from other 

studies)

Nuclear—2.8 to 24 g Ceq/kWh

Coal—950 to 1250 g Ceq/kWh

6.2.8 Summary of Nuclear Greenhouse Gas Emissions Compared to Natural Gas

The quantitative estimates of the GHG emissions associated with the nuclear fuel cycle, as 

compared to an equivalent natural gas-fired plant, are presented in Table 6-3.
Environmental Impacts of the Uranium Fuel Cycle

6-7

Table 6-3. Nuclear Greenhouse Gas Emissions Compared to Natural Gas

Source GHG Emission Results

Spadaro 2000 Nuclear—2.5 to 5.7 g Ceq/kWh 

Natural Gas—120 to 188 g Ceq/kWh

Storm van 

Leeuwen and 

Smith 2005

Nuclear fuel cycle produces 20 to 33% of the GHG emissions compared to 

natural gas (at high ore grades).

Note: Future nuclear GHG emissions to increase because of declining ore 

grade.

Fritsche 2006 

(values estimated 

from graph in 

Figure 4)

Nuclear—33 g Ceq/kWh

Cogeneration Combined Cycle Natural Gas—150 g Ceq/kWh

POST 2006 

(Nuclear 

calculations from 

AEA 2006)

Nuclear—5 g Ceq/kWh

Natural Gas—500 g Ceq/kWh

Note: Decrease of uranium ore grade to 0.03% would raise nuclear to 

6.8 g Ceq/kWh. Future improved technology and carbon capture and 

storage could reduce natural gas GHG emissions by 90%.

Weisser 2006

(compilation of 

results from other 

studies)

Nuclear—2.8 to 24 g Ceq/kWh

Natural Gas—440 to 780 g Ceq/kWh

Dones 2007 Author critiqued methods and assumptions of Storm van Leeuwen and 

Smith (2005), and concluded that the nuclear fuel cycle produces 15 to 27%

of the GHG emissions of natural gas.

6.2.9 Summary of Nuclear Greenhouse Gas Emissions Compared to Renewable Energy 

Sources

The quantitative estimates of the GHG emissions associated with the nuclear fuel cycle, as 

compared to equivalent renewable energy sources, are presented in Table 6-4. Calculation of 

GHG emissions associated with these sources is more difficult than the calculations for nuclear 

energy and fossil fuels because the efficiencies of the different energy sources vary so much by 

location. For instance, the efficiency of solar and wind energy is highly dependent on the 

location in which the power generation facility is installed. Similarly, the range of GHG emissions 

estimates for hydropower varies greatly depending on the type of dam or reservoir involved.

Therefore, the GHG emissions estimates for these energy sources have a greater range of 

variability than the estimates for nuclear and fossil fuel sources.
Environmental Impacts of the Uranium Fuel Cycle 

6-8

Table 6-4. Nuclear Greenhouse Gas Emissions Compared to Renewable Energy Sources

Source GHG Emission Results

Mortimer 1990 Nuclear—230,000 tons CO2

Hydropower—78,000 tons CO2

Wind power—54,000 tons CO2

Tidal power—52,500 tons CO2

Note: Future GHG emissions from nuclear to increase because of declining 

ore grade.

Spadaro 2000 Nuclear—2.5 to 5.7 g Ceq/kWh 

Solar PV—27.3 to 76.4 g Ceq/kWh

Hydroelectric—1.1 to 64.6 g Ceq/kWh

Biomass—8.4 to 16.6 g Ceq/kWh

Wind—2.5 to 13.1 g Ceq/kWh

Fritsche 2006 

(values estimated 

from graph in 

Figure 4)

Nuclear—33 g Ceq/kWh 

Solar PV—125 g Ceq/kWh

Hydroelectric—50 g Ceq/kWh

Wind—20 g Ceq/kWh

POST 2006 

(Nuclear 

calculations from 

AEA 2006)

Nuclear—5 g Ceq/kWh 

Biomass—25 to 93 g Ceq/kWh

Solar PV—35 to 58 g Ceq/kWh

Wave/Tidal—25 to 50 g Ceq/kWh

Hydroelectric—5 to 30 g Ceq/kWh

Wind—4.64 to 5.25 g Ceq/kWh

Note: Decrease of uranium ore grade to 0.03% would raise nuclear to 

6.8 g Ceq/kWh.

Weisser 2006 

(compilation of 

results from other 

studies)

Nuclear—2.8 to 24 g Ceq/kWh 

Solar PV—43 to 73 g Ceq/kWh

Hydroelectric—1 to 34 g Ceq/kWh

Biomass—35 to 99 g Ceq/kWh

Wind—8 to 30 g Ceq/kWh

Fthenakis and Kim 

(2007)

Nuclear—16 to 55 g Ceq/kWh 

Solar PV—17 to 49 g Ceq/kWh

Dones 2007 Author did not evaluate nuclear versus renewable energy sources.
Environmental Impacts of the Uranium Fuel Cycle

6-9

6.2.10 Conclusions

Estimating the GHG emissions associated with current nuclear energy sources is challenging 

because of differing assumptions and noncomparable analyses performed by the various 

authors. The differences and complexities in these assumptions and analyses increase when 

using them to project future GHG emissions. However, even with these differences, the NRC 

staff can draw several conclusions.

First, the studies indicate a consensus that nuclear power currently produces fewer GHG 

emissions than fossil-fuel-based electrical generation. Based on the literature review, the 

lifecycle GHG emissions from the complete nuclear fuel cycle currently range from 2.5 to 

55 g Ceq/kWh. The comparable lifecycle GHG emissions from the current use of coal range from 

264 to 1250 g Ceq/kWh, and GHG emissions from the current use of natural gas range from 120 

to 780 g Ceq/kWh. The existing studies also provided estimates of GHG emissions from five 

renewable energy sources, based on current technology. These estimates included solarphotovoltaic (17 to 125 g Ceq/kWh), hydroelectric (1 to 64.6 g Ceq/kWh), biomass (8.4 to 99 g 

Ceq/kWh), wind (2.5 to 30 g Ceq/kWh), and tidal (25 to 50 g Ceq/kWh). The range of these 

estimates is very wide, but the general conclusion is that the current GHG emissions from the 

nuclear fuel cycle are of the same order of magnitude as those for these renewable energy 

sources.

Second, the studies indicate no consensus on future relative GHG emissions from nuclear 

power and other sources of electricity. There is substantial disagreement among the various 

authors regarding the GHG emissions associated with declining uranium ore concentrations, 

future uranium enrichment methods, and other factors, including changes in technology. Similar 

disagreement exists regarding future GHG emissions associated with coal and natural gas 

electricity generation. Even the most conservative studies conclude that the nuclear fuel cycle 

currently produces fewer GHG emissions than fossil-fuel-based sources, and are expected to 

continue to do so in the near future. The primary difference between the authors is the projected 

cross-over date (the time at which GHG emissions from the nuclear fuel cycle exceed those of 

fossil-fuel-based sources) or whether cross-over will actually occur at all.

Considering the current estimates and future uncertainties, it appears that GHG emissions 

associated with the proposed PINGP 1 and 2 relicensing action are likely to be lower than those 

associated with fossil-fuel-based energy sources. The NRC staff bases this conclusion on the 

following rationale:

1) The current estimates of GHG emissions from the nuclear fuel cycle are far 

below those for fossil-fuel-based energy sources.

2) PINGP 1 and 2 license renewal will involve continued GHG emissions due to 

uranium mining, processing, and enrichment, but will not result in increased 

GHG emissions associated with plant construction or decommissioning (as 

the plant will have to be decommissioned at some point whether the license 

is renewed or not).

3) Few studies predict that nuclear fuel cycle emissions will exceed those of 

fossil fuels within a timeframe that includes the PINGP 1 and 2 periods of 

extended operation. Several studies suggest that future extraction and 

enrichment methods, the potential for higher grade resource discovery, and 

technology improvements could extend this timeframe.

With respect to comparison of GHG emissions between the proposed PINGP 1 and 2 license 

renewal action and renewable energy sources, it appears likely that there will be future 

technology improvements and changes in the type of energy used for mining, processing, and 
Environmental Impacts of the Uranium Fuel Cycle 

6-10

constructing facilities in both areas. Currently, the GHG emissions associated with the nuclear 

fuel cycle and renewable energy sources are within the same range. Because nuclear fuel 

production is the most significant contributor to possible future increases in GHG emissions 

from nuclear power, and because most renewable energy sources lack a fuel component, it is 

likely that GHG emissions from renewable energy sources would be lower than those 

associated with PINGP 1 and 2 at some point during the period of extended operation.

6.3 References 

10 CFR 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental Protection 

Regulations for Domestic Licensing and Related Regulatory Functions.”

10 CFR 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for Renewal 

of Operating Licenses for Nuclear Power Plants.”

10 CFR Part 63. Code of Federal Regulations, Title 10, Energy, Part 63, “Disposal of High-Level 

Radioactive Wastes in a Geologic Repository at Yucca Mountain, Nevada.” 

40 CFR Part 191. Code of Federal Regulations, Title 40, Protection of Environment, Part 191, 

“Environmental Radiation Protection Standards for Management and Disposal of Spent Nuclear 

Fuel, High-Level and Transuranic Radioactive Waste.”

AEA (AEA Technology). 2006. “Carbon Footprint of the Nuclear Fuel Cycle, Briefing Note.”

Prepared for British Energy. March 2006.

Andseta, S., M.J. Thompson, J.P. Jarrell, and D.R. Pendergast. 1998. “CANDU Reactors and 

Greenhouse Gas Emissions.” Canadian Nuclear Association, 11th Pacific Basin Nuclear 

Conference, Banff, Alberta, Canada. May 1998.

DOE (Department of Energy). 1980. “Final Environmental Impact Statement: Management of 

Commercially Generated Radioactive Waste.” DOE/EIS-0046F, Washington, DC.

Dones, R. 2007. “Critical Note on the Estimation by Storm Van Leeuwen J.W. and Smith P. of 

the Energy Uses and Corresponding CO2 Emissions for the Complete Nuclear Energy Chain.”

Paul Sherer Institute. April 2007.

Fritsche, U.R. 2006. “Comparison of Greenhouse-Gas Emissions and Abatement Cost of 

Nuclear and Alternative Energy Options from a Life-Cycle Perspective.” Oko-Institut, Darmstadt 

Office. January 2006.

Fthenakis, V.M., and H.C. Kim. 2007. Greenhouse-gas emissions from solar electric- and 

nuclear power: A life cycle study. Energy Policy, Volume 35, Number 4.

Hagen, R.E., J.R. Moens, and Z.D. Nikodem. 2001. “Impact of U.S. Nuclear Generation on 

Greenhouse Gas Emissions.” International Atomic Energy Agency, Vienna, Austria. November 

2001.

IAEA (International Atomic Energy Agency). 2000. “Nuclear Power for Greenhouse Gas 

Mitigation under the Kyoto Protocol: The Clean Development Mechanism (CDM).” November 

2000.

Joint Resolution 87, 2002. Public Law 107-200, 116 Stat 735.

Keepin, B. 1988. “Greenhouse Warming: Efficient Solution of Nuclear Nemesis?” Rocky 

Mountain Institute. Joint Hearing on Technologies for Remediating Global Warming, 

Subcommittee on Natural Resources, Agriculture Research and Environment and 

Subcommittee on Science, Research and Technology, United States House of Representatives.

June 1988.
Environmental Impacts of the Uranium Fuel Cycle

6-11

MIT (Massachusetts Institute of Technology). 2003. “The Future of Nuclear Power: An 

Interdisciplinary MIT Study.”

Mortimer, N. 1990. World warms to nuclear power. SCRAM Safe Energy Journal. December 

1989 and January 1990. Available at URL:

http://www.no2nuclearpower.org.uk/articles/mortimer_se74.php. Accessed February 29, 2007.

NAS (National Academy of Sciences). 1995. “Technical Bases for Yucca Mountain Standards.”

Washington, DC.

NEA (Organization for Economic Co-Operation and Development, Nuclear Energy Agency).

2002. Nuclear Energy and the Kyoto Protocol.

NEPA (National Environmental Policy Act of 1969). 42 U.S.C. 4321, et seq. 

NIRS/WISE (Nuclear Information and Resource Service and World Information Service on 

Energy). 2005. Nuclear power: No solution to climate change. Nuclear Monitor, Numbers 621 

and 622. February 2005.

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NRC. (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, Washington, DC. Nos. 

ML040690705 and ML040690738.

NRC. (U.S. Nuclear Regulatory Commission). 1999. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, Main Report, “Section 6.3 – Transportation, Table 9.1, 

Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final 

Report.” NUREG-1437, Volume 1, Addendum 1, Washington, DC.

POST (Parliamentary Office of Science and Technology). 2006. “Carbon Footprint of Electricity 

Generation.” Postnote, Number 268. October 2006.

Schneider, M. 2000. Climate Change and Nuclear Power. World Wildlife Fund for Nature. April 

2000.

Spadaro, J.V., L. Langlois, and B. Hamilton. 2000. “Greenhouse Gas Emissions of Electricity 

Generation Chains: Assessing the Difference.” IAEA Bulletin 42/2/2000, Vienna, Austria.

Storm van Leeuwen, J.W., and P. Smith. 2005. Nuclear Power—The Energy Balance. August 

2005.

Weisser, D. 2006. “A Guide to Life-Cycle Greenhouse Gas (GHG) Emissions from Electric 

Supply Technologies.” Available at URL: 

http://www.iaea.org/OurWork/ST/NE/Pess/assets/GHG_manuscript_preprint_versionDanielWeisser.pdf. Accessed May 19, 2009.



7-1

7.0 ENVIRONMENTAL IMPACTS OF DECOMMISSIONING

Decommissioning is defined as the safe removal of a nuclear facility from service and the 

reduction of residual radioactivity to a level that permits release of the property for unrestricted 

use and termination of the license. The U.S. Nuclear Regulatory Commission (NRC) issued the

Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities (NRC 2002) 

that evaluated the environmental impacts from the activities associated with the 

decommissioning of any reactor before or at the end of an initial or renewed license.

The NRC staff has not identified any new and significant information during the review of the 

Northern State Power Co. (NSP) environmental report (ER; NMC 2008), the site audit, or the 

scoping process. Therefore, there are no impacts related to these issues beyond those 

discussed in the GEIS (NRC 1996, 1999). For the issues listed in table 7-1 below, the GEIS 

concluded that the impacts are SMALL.

Plant shutdown will likely have no noticeable impacts on historic and archaeological resources 

at the PINGP 1 and 2 site. NRC requirements ensure that the decommissioning activities for 

PINGP 1 and 2 would be subject to a Section 106 review in accordance with the National 

Historic Preservation Act (NHPA). In Chapter 4, the NRC concluded that the impacts of 

continued plant operation on historic and archaeological resources could be MODERATE. 

Since plant shutdown would not involve any land disturbance, the NRC concludes that the 

impacts on historic and archaeological resources from plant shutdown would be SMALL.

Table 7-1. Issues Related Decommissioning. Decommissioning would occur 

regardless of whether Prairie Island Nuclear Generating Plant , Units 1 and 2, are shut 

down at the end of their current operating licenses or at the end of the period of 

extended operation. There are no site-specific issues related to decommissioning.

Issues GEIS Section Category

Radiation doses 7.3.1; 7.4 1

Waste management 7.3.2; 7.4 1

Air quality 7.3.3; 7.4 1

Water quality 7.3.4; 7.4 1

Ecological resources 7.3.5; 7.4 1

Socioeconomic impacts 7.3.7; 7.4 1

7.1 References

NRC (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, NUREG-1437, Vols. 1 and 2. Washington, D.C. ADAMS 

Nos. ML040690705 and ML040690738.

NRC (U.S. Nuclear Regulatory Commission). 1999. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, Main Report, “Section 6.3, Transportation, Table 9.1, 

Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final 

Report.” NUREG-1437, Volume 1, Addendum 1. Washington, D.C. 
Environmental Impacts of Decommissioning

7-2

NRC (U.S. Nuclear Regulatory Commission). 2002. Generic Environmental Impact Statement 

on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the Decommissioning of 

Nuclear Power Reactors. NUREG-0586, Supplement

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.
8-1

8.0 ENVIRONMENTAL IMPACTS OF ALTERNATIVES

The National Environmental Policy Act of 1969 (NEPA) mandates that each environmental 

impact statement (EIS) consider alternatives to any proposed major federal action. NRC 

regulations implementing NEPA for license renewal require that a supplemental EIS “considers 

and weighs the environmental effects of the proposed action [license renewal]; the 

environmental impacts of alternatives to the proposed action; and alternatives available for 

reducing or avoiding adverse environmental impacts,” [10 CFR 51.71(d)]. In this case, the 

proposed Federal action is issuing renewed licenses for Prairie Island Nuclear Generating Plant, 

Units 1 and 2 (PINGP 1 and 2), which will allow the plant to operate for 20 years beyond their 

current license expiration dates. 

In this chapter, we examine the potential environmental impacts of alternatives to issuing 

renewed operating licenses for PINGP 1 and 2, as well as alternatives that may reduce or avoid 

adverse environmental impacts from license renewal, when and where these alternatives are 

applicable.

While the Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 

NUREG-1437 (GEIS; NRC 1996; 1999), reached generic conclusions regarding many 

environmental issues associated with license renewal, it did not determine which alternatives 

are reasonable or reach conclusions about site-specific environmental impact levels. Therefore, 

the NRC staff must evaluate environmental impacts of alternatives on a site-specific basis. 

In accordance with the GEIS, alternatives to the proposed action of issuing renewed PINGP 1 

and 2 operating licenses must meet the purpose and need for issuing a renewed license; they 

must: 

provide an option that allows for power generation capability beyond the term of 

a current nuclear power plant operating license to meet future system generating 

needs, as such needs may be determined by State, utility, and, where 

authorized, Federal (other than NRC) decision makers.

The NRC staff ultimately make no decision regarding which alternative, or whether the proposed 

action, is implemented, since that decision falls to utility, State, or other Federal officials. 

Comparing the environmental effects of these alternatives will assist the NRC staff in deciding 

whether the environmental impacts of license renewal are so great that preserving the option of 

license renewal for energy-planning decision makers would be unreasonable 

[10 CFR 51.95(c)(4)]. If the NRC acts to issue a renewed license, all of the alternatives, 

including the proposed action, will be available to energy-planning decision makers. If the NRC 

decides not to renew the license (or takes no action at all), then energy-planning decision 

makers may no longer elect to continue operating PINGP 1 and 2 and will have to resort to 

another alternative, which may or may not be one of the alternatives the NRC staff considers in 

this section, in order to meet their energy needs.

In addition to evaluating alternatives to the proposed action, when appropriate, the NRC staff 

also examine alternatives that may reduce or avoid environmental impacts of the proposed 

action; the staff does so to illustrate how such alternatives may act to mitigate potential impacts 

of license renewal. 

In evaluating alternatives to license renewal, the NRC staff first selects energy technologies or 

options currently in commercial operation as well as some technologies not currently in 

commercial operation but likely to be commercially available by the time the current PINGP 1 

and 2 operating licenses expire. 
Alternatives

8-2

In-Depth Alternatives:

• Natural-gas-fired 

combined-cycle

• Combination 

including natural gas, 

wind, wood-fired 

generation

• Combination 

including one nuclear

unit, natural gas, and 

wind

Other Alternatives 

Considered:

• Wind Power

• Wood Waste

• Conservation

• Solar Power

• Conventional 

Hydroelectric Power

• Geothermal Power

• Biofuels

• New nuclear

• Coal-fired power

• Oil-fired Power

• Fuel Cells

• Municipal Solid Waste

• Delayed Retirement

Second, the NRC staff screens the alternatives to remove 

those that cannot meet future system needs. Then, the 

NRC staff screens the remaining options to remove those 

for which the cost or benefits do not justify inclusion in the 

range of reasonable alternatives. Any alternatives

remaining, then, constitute alternatives to the proposed 

action that the NRC staff evaluates in-depth throughout 

this section. At the end of the section, the NRC staff briefly 

addresses each alternative that was removed during 

screening. 

The NRC staff initially considered 14 discrete potential 

alternatives to the proposed action and narrowed the list to 

one single-source alternative and two combination 

alternatives considered in this chapter. In addition, the 

NRC staff considered purchased power, but not as a 

discrete alternative to license renewal, because the power 

sources for purchased power would likely be similar to 

those considered in this section, but may include older, 

less clean and efficient power plants. Also, Minnesota’s 

Next Generation Energy Act of 2007 (136-S.F.No. 145) 

restricts importation of power from certain power plants, 

including essentially any new coal-fired power plant. 

Once the NRC staff identified the in-depth alternatives, it 

referred to generic environmental impact evaluations in the 

GEIS. The GEIS provides overviews of some energy 

technologies available at the time of its publishing in 1996, 

though it does not reach any conclusions regarding which 

alternatives are most appropriate, nor does it precisely 

categorize impacts for each site. Since 1996, many energy 

technologies have evolved significantly in capability and 

cost, while regulatory structures have changed to either promote or impede development of 

particular alternatives. 

Where applicable, the NRC staff uses information in the GEIS and includes updated information 

from the Energy Information Administration (EIA), other organizations within the Department of 

Energy (DOE), the U.S. Environmental Protection Agency (EPA), industry sources and 

publications, and information submitted by Northern States Power Co. (NSP) in the 

environmental report (ER). 

For each in-depth analysis, the NRC staff analyzes environmental impacts across seven impact 

categories: air quality, ground water use and quality, surface water use and quality, ecology, 

human health, socioeconomics, and waste management. As in earlier chapters of this 

supplemental environmental impact statement (SEIS), the NRC staff uses the NRC’s three-level 

standard of significance – SMALL, MODERATE, or LARGE – to indicate the intensity of 

environmental effects for each alternative that the NRC staff evaluates in-depth.
Alternatives

8-3

Energy Outlook: Each year the Energy 

Information Administration (EIA), part of the 

U.S. Department of Energy (DOE), issues 

its updated Annual Energy Outlook (AEO).

AEO 2008 indicates that coal and natural

gas are likely to fuel most new electrical

capacity through 2030, with significant

contributions from new renewable sources,

and some growth in nuclear capacity (EIA

2008a), though all projections are subject 

to future developments in fuel price or

electricity demand:

“Natural-gas-fired plants generally have

lower capacity costs but higher fuel 

costs than coal-fired plants. As a result, 

coal-fired plants account for 40 percent 

of total capacity additions from 2006 to

2030, compared with a 36-percent share

for natural gas. Renewable and nuclear

plants tend to have high investment

costs and relatively low operating costs.

EPACT2005 and State RPS programs

are expected to stimulate generation

from renewable and nuclear plants,

which represent 18 percent and 6

percent of total additions, respectively. 

The quantity and mix of capacity

additions can also be affected by

different fuel price paths or growth rates

for electricity demand.”

By placing the detailed alternative analyses in 

this order, the NRC staff does not imply which 

alternative would have the least impact, or 

which alternative an energy planning decision 

maker would be most likely to implement. 

Whenever possible, the NRC staff considers 

effects from locating the alternative at the 

existing site, as well as at an alternate site. 

Sections 8.1 through 8.3, include the NRC 

staff’s analysis of environmental impacts of 

alternatives to license renewal. These include 

a gas-fired alternative located both at the 

PINGP 1 and 2 site and at a different site 

(8.1), a combination alternative including gasfired capacity at the PINGP 1 and 2 site as 

well as renewable capacity at other sites and 

conservation (8.2), and a combination 

alternative that includes continued operation of 

one PINGP 1 and 2 unit as well as renewables 

and conservation (8.3). In section 8.4, the 

NRC staff briefly discusses purchased power.

In section 8.5, the NRC staff addresses 

alternatives excluded from in-depth analysis 

and addresses why they were excluded.

Finally, in section 8.6, the NRC staff considers 

the environmental effects that occur if NRC 

takes no action and does not issue renewed 

licenses for PINGP 1 and 2.

Notably, the NRC staff’s alternatives analysis 

for PINGP 1 and 2 license renewal excludes 

several alternatives the NRC staff typically 

analyzes for license renewal. As discussed in 

greater depth in Section 8.4, the NRC staff found that Minnesota regulations restricting 

greenhouse gas emissions would make building a coal-fired alternative difficult regardless of 

combustion technology used. The NRC staff also found that the lead time remaining prior to the 

expiration of current PINGP 1 and 2 licenses make it unlikely that a replacement nuclear plant 

could be permitted and constructed prior to license expiration. The alternatives that NRC staff 

considered in depth, then, focus primarily on natural gas-fired generation, wind, wood waste 

biomass, and conservation resources. 

8.1 Gas-fired Generation

In this section, the NRC staff evaluates the environmental impacts of natural gas-fired 

generation at both the PINGP 1 and 2 site and at an alternate site. 

Natural gas fueled 20 percent of electric generation in the U.S. in 2006, the most recent year for 

which data are available, accounting for the second greatest share of electrical power after coal 

(EIA 2007a). Like coal-fired power plants, natural-gas-fired plants may be affected by perceived 

or actual action to limit greenhouse gas emissions, though they produce markedly fewer 

greenhouse gases per unit of electrical output than coal-fired plants. Natural gas-fired power 
Alternatives

8-4

plants are feasible, commercially-available options for providing electrical generating capacity 

beyond the current license terms for PINGP 1 and 2.

Combined-cycle power plants differ significantly from power plants that generate electricity 

solely from a steam cycle, as almost all coal-fired and all existing nuclear power plants do.

Combined-cycle power plants derive the majority of their electrical output from a gas-turbine 

cycle, and then generate additional power – without burning any additional fuel – through a 

second, steam-turbine cycle. The first, gas-turbine stage (similar to a large jet engine) burns 

natural gas that turns a driveshaft to power an electric generator. Ducts carry the hot exhaust

from the turbine to a heat recovery steam generator, which then produces steam to drive 

another turbine and produce additional electrical power. The combined-cycle approach is 

significantly more efficient than any one cycle on its own; efficiencies can exceed 60 percent.

Natural gas combined-cycle generation requires less cooling water and smaller cooling towers

than the existing PINGP 1 and 2 units, partly because of greater thermal efficiency. In order to 

replace the 1044 megawatts electrical (MWe) that PINGP 1 and 2 currently supply, the NRC 

staff selected a gas-fired alternative that uses two General Electric Company (GE) S207FB

combined-cycle generating units. While any number of commercially-available combined-cycle 

units could be installed in a variety of combinations to replace the power currently produced by 

PINGP 1 and 2, the S207FB is an efficient model that operates at a heat rate of 5940 British 

thermal units per kilowatt hour (Btu/kWh), or 57.4 percent thermal efficiency (GE 2007). GE and 

other manufacturers, like Siemens, offer similar high efficiency models, including several that 

slightly exceed the thermal efficiency of this model. The NRC staff selected this particular 

configuration because it is able to provide almost the same amount of electricity as PINGP 1 

and 2. This gas-fired alternative produces 562.5 MWe per unit. Two units produce a total of

1125 MWe — or, after accounting for 4 percent onsite usage including site lighting, cooling 

towers, and emissions controls — nearly the same output as PINGP 1 and 2. Cooling towers for 

this alternative would likely be mechanical draft-type towers approximately 65 ft (20 m) in height

and similar in appearance and function to the existing PINGP 1 and 2 cooling towers.

In addition to cooling towers, other visible structures onsite would include the turbine buildings

and heat recovery steam generators (which may be enclosed in the turbine building), two 

exhaust stacks, an electrical switchyard, and, possibly, equipment associated with a natural gas 

pipeline, like a compressor station. The GEIS estimated that a 1000 MWe gas-fired alternative 

would require 110 ac (40 ha), meaning this 1125-MWe plant would require 129 ac (52 ha). In 

their ER, NSP (NMC 2008) indicated that the plant would require 41 ac (17 ha), a number more 

consistent with minimum utility needs as demonstrated by existing power plants (including 

Dominion Resources’ Fairless Energy Works located in Falls Township, Pennsylvania). The 

NRC staff uses NSP’s estimate for the purposes of the following analysis. 

This 1125-MWe power plant would consume 50.2 billion ft3 (1.4 billion m3

) of natural gas 

annually, assuming an average heat content of 1,033 Btu/ft3 (EIA 2006). Natural gas would be 

extracted from the ground through wells, then treated to remove impurities (like hydrogen 

sulfide), and blended to meet pipeline gas standards, before being piped through the interstate 

pipeline system to the power plant site. This gas-fired alternative would produce relatively little 

waste, which would primarily be in the form of spent catalysts used for emissions controls.

Spent catalysts are generally recycled.

Environmental impacts from the gas-fired alternative will be greatest during construction. Site 

crews will clear vegetation from the site, prepare the site surface, and begin excavation before 

other crews begin actual construction on the plant and any associated infrastructure, including a 

pipeline spur to serve the plant and electricity transmission infrastructure connecting the plant to 

existing transmission lines.
Alternatives

8-5

Constructing the gas-fired alternative on the PINGP 1 and 2 site would allow the gas-fired 

alternative to make use of the site’s existing transmission system, as well as take advantage of 

partially cleared areas of the site.

A gas-fired unit constructed offsite may cause additional construction-related impacts depending 

on the nature of the site selected. A site that has never been developed will likely experience 

greater impacts than a site that was previously industrial; a site near other power plants or 

industrial facilities will likely experience smaller impacts than a site surrounded by farmland or 

relatively natural surroundings.

Table 8-1. Summary of Environmental Impacts of Gas-Fired Combined-Cycle Generation

Compared to Continued PINGP 1 and 2 Operation

Gas-fired combined-cycle Continued

PINGP 1 and 2 

Operation At PINGP 1 and 2 site At alternate site

Air Quality MODERATE MODERATE SMALL

Ground Water SMALL SMALL SMALL

Surface Water SMALL SMALL SMALL

Ecology SMALL SMALL TO MODERATE SMALL

Human Health SMALL SMALL SMALL

Socioeconomics SMALL TO MODERATE SMALL TO MODERATE SMALL TO 

MODERATE

Waste Management SMALL SMALL SMALL

8.1.1 Air Quality

With the exception of Olmstead County, all Minnesota counties within the Southeast Minnesota–

La Crosse (Wisconsin) Interstate Air Quality Control Region are in attainment for all Clean Air 

Act (CAA) criteria pollutants. Olmsted County, which is located approximately 30 mi (48 km) to 

the south of PINGP 1 and 2, is a maintenance county for sulfur dioxide (SO2) and particulate 

matter (PM10). 

A new gas-fired generating plant, would qualify as a new major-emitting industrial facility and 

require a New Source Review and a Title V permit under the CAA (EPA 2007a). The New

Source Review program requires that a permit be obtained before construction of a new majoremitting industrial facility (42 U.S.C. §7475(a)). The permit will be issued only if the new plant 

includes pollution control measures that reflect the Best Available Control Technology standard 

mandated by the CAA. The natural gas-fired plant would need to comply with the standards of 

performance for electric utility steam generating units set forth in 40 CFR Part 60, Subpart D, 

“Standards of Performance for New Stationary Sources.” Additionally, Additionally, construction 

of a new electric production facility of greater than 25 MWe capacity would trigger the state 

environmental review process, found in Minnesota Administrative Review 4410, “Environmental 

Review.” As part of the review, the Minnesota Pollution Control Agency (MPCA) requires the 

submissions of an Air Emission Risk Analysis for hazardous air pollutants, and a Greenhouse 

Gas Emissions Evaluation. Emissions sources constructed in attainment or unclassified areas 

that may have an effect on visibility in designated Federal Class I areas, as defined by 

Protection of Visibility provisions (40 CFR Part 51, Subpart P), must complete a new source 

review. The closest Federal Class I areas to the PINGP 1 and 2 site are Boundary Waters 
Alternatives

8-6

Canoe Area Wilderness Area, located approximately 230 mi (370 km) north-northeast of the 

PINGP 1 and 2 site, and Voyageurs National Park, located 260 mi (420 km) north-northwest of 

the PINGP 1 and 2 site. If the gas-fired alternative were constructed near or at the PINGP 1 and 

2 site, it is unlikely that this additional requirement would apply, as the nearest Federal Class I 

areas in Minnesota would not be significantly affected due to the distance from the site.

The projected emissions from this natural gas-fired alternative based on published EIA data, 

EPA emission factors, performance characteristics for this alternative, and implemented 

emission controls are as follows:

Sulfur dioxide (SO2) – 88.11 tons (79.94 MT) per year;

Nitrogen oxides (NOx) – 282.48 tons (256.27 MT) per year;

Carbon monoxide (CO) – 58.72 tons (53.28 MT) per year;

Total suspended particles/PM10 – 49.24 tons (44.67 MT) per year;

Carbon dioxide (CO2) – 3,031,481.84 tons (2,750,160.32 MT) per year.

The new natural gas-fired plant would have to comply with Title IV of the CAA reduction 

requirements for SO2 and NOx. These compounds are precursors of acid rain and are major 

contributors to reduced visibility. Title IV establishes maximum SO2 and NOx emission rates

from existing plants and a system of the SO2 emission allowances that can be used, sold, or 

saved for future use by the new plants. 

As stated above, the new natural gas-fired alternative would produce 88.11 tons (79.94 MT) per 

year of SO2 and 282.48 tons (256.27 MT) per year of NOx based on the use of the dry-low NOx

combustion technology and the use of the selective catalytic reduction in order to significantly 

reduce NOx emissions. 

The new plant would be subject to the continuous monitoring requirements of SO2 and 

NOx,specified in 40 CFR Part 75and CO specified in 40 CFR Part 60. The natural gas-fired plant 

would emit approximately 2.9 million tons (approximately 2.6 million MT) per year of unregulated 

CO2 emissions. Minnesota Statute §216H (added as part of the Next Generation Energy Act of 

2007) stipulates greenhouse gas emissions reporting requirements and statewide adoption of a 

climate change action plan, which requires a reduction in greenhouse gases. Minnesota also 

voluntarily participates in the Climate Registry which establishes and endorses a greenhouse 

gas emissions inventory across North America. The inventory contains verified and accurate 

data available to the public and is published as general reporting protocol.

This alternative would emit 49.24 tons (44.67 MT) per year of particulate matter having an 

aerodynamic diameter less than or equal to 10 μm (PM10) (40 CFR 50.6a). All suspended 

particles emitted by this alternative are PM10.

Activities associated with the construction of the new natural gas-fired plant onsite or offsite of 

the PINGP 1 and 2 site would cause some additional air effects as a result of equipment 

emissions and fugitive dust from operation of the earth-moving and material handling 

equipment. Exhaust emissions from workers’ vehicles and construction equipment would be 

temporary. The construction crews would employ dust-control practices in order to control and 

reduce fugitive dust, which would be temporary in nature. The NRC staff concludes that the 

impact of vehicle exhaust emissions and fugitive dust from operation of the earth-moving and 

material handling equipment would be SMALL. 

The overall air-quality impacts of a new natural gas-fired plant located at the PINGP 1 and 2 site 

or at an alternate site would be MODERATE.
Alternatives

8-7

8.1.2 Ground Water Use and Quality

The use of ground water for a gas-fired plant in Minnesota would likely be limited to supply wells 

for drinking water, pump and valve cooling, filtered service water for system cleaning purposes, 

and landscaping. The number, depth, and location of the wells would be specific to the site 

selected for the plant. One onsite plant located on the PINGP 1 and 2 site with two units would 

use the same shallow alluvial aquifer and the bedrock Franconia formation as the existing 

nuclear plant for sources of ground water supply. The average pumping rate would likely range 

from 75 to 100 gpm which is less than the current use of ground water.

A gas-fired plant at an offsite location would require wells, which would vary in depth depending 

on ground water and aquifer resources at the site. Generally, Minnesota has abundant ground 

water supplies, but the aquifer(s) selected for use at a given location will depend on ground 

water quality requirements and the location of existing water supply wells with higher water 

appropriation priorities.

The amount of ground water needed to service the alternative natural gas-fired plants is 

relatively low and the impact of ground water use would be SMALL. No effects on ground water

quality would be apparent, except during the construction phase when possible dewatering and 

run-off controls are used. The construction phase should implement best management practices 

to minimize any potential construction impacts.

8.1.3 Surface Water Use and Quality

Consumptive surface water use for either an onsite or offsite natural gas-fired alternative would 

be approximately half the volume needed for PINGP 1 and 2 because of a higher efficiency of 

cooling water used per given unit of energy production. Waste water discharge at the gas-fired 

plant would be minimal. If the alternative is placed on the existing site, all intakes and 

discharges would be on the Mississippi River, and the impact on surface water resources, both 

in quantity and quality, would be SMALL. An offsite location would have different intake and 

discharge points that would require a National Pollutant Discharge Elimination System (NPDES)

permit from the MPCA, but the scale of water use would be the same as for the onsite plant.

Therefore, the impact of the offsite plant on surface water use and quality would also be 

SMALL.

8.1.4 Aquatic and Terrestrial Ecology

Impacts to aquatic ecology would be minimal, as the consumptive water use of a natural gasfired plant would be less than half that of the current consumption rate of PINGP 1 and 2.

Additionally, the onsite natural gas-fired plant could use parts of the existing cooling system, 

which would reduce potential impacts to aquatic resources. Impacts of the offsite alternative to 

aquatic resources would depend on location, the ecology of the site and the source and 

receiving water body. Construction in a previously disturbed area would have lower impacts to 

the aquatic resources than construction in an undisturbed area. Overall, the impacts to aquatic 

resources from a natural gas-fired plant would be SMALL for an onsite natural gas-fired plant, 

but could range from SMALL to MODERATE for an offsite plant, depending on the ecological 

conditions of the alternate site.

As indicated in previous sections, constructing the natural gas-fired alternative will require 41 ac 

(17 ha) of land, according to calculations presented in the ER (NMC 2008). Impacts to terrestrial 

ecology from the onsite alternative will be minor because the selected site has been previously 

disturbed. Buildings and structures associated with PINGP 1 and 2 occupy approximately 60 ac 

(24 ha) of the site (NMC 2008); therefore, some areas of previously disturbed land may return to 
Alternatives

8-8

natural habitat as a result of this alternative because less land would be required than is 

currently in use for PINGP 1 and 2. Buffer areas and surrounding wetland habitat on or in the 

vicinity of the site may remain undeveloped and would continue to provide habitat for terrestrial 

species, though site lighting, noise, and activities may degrade the value of these neighboring 

habitats. Construction of additional transmission line rights-of-way (ROWs) is unlikely because 

existing transmission capacity at the PINGP 1 and 2 site could be used. Any lengthy pipelines or 

additional roads on undisturbed or less-disturbed areas could adversely impact terrestrial 

ecology by fragmenting or destroying habitats. However, a pipelined fuel source and a small

workforce would help to minimize the need for additional transportation infrastructure. Gas 

extraction and collection will also affect terrestrial ecology in offsite gas fields, although much of 

this land is likely already disturbed by gas extraction, and the incremental effects of this 

alternative on gas field terrestrial ecology are difficult to gauge. Deposition of air pollutants from 

this alternative may affect terrestrial ecology, but it is unlikely to be noticeable. Impacts to 

terrestrial resources from a natural gas-fired alternative at the PINGP 1 and 2 site would likely 

be SMALL.

Impacts of the offsite alternative to terrestrial resources would depend on location and whether 

the land was previously disturbed or located near any unique natural habitats. Construction in 

previously disturbed areas would have lower impacts than construction in an undisturbed area. 

Because impacts may vary widely based on the natural habitat of an alternate site, impacts to 

terrestrial resources from an offsite natural gas-fired alternative would range from SMALL to 

MODERATE. 

8.1.5 Human Health

A natural gas-fired alternative would release a variety of air pollutants. EPA establishes National 

Ambient Air Quality Standards (NAAQS) for six criteria pollutants (40 CFR Part 50) under the 

CAA. The CAA recognizes two types of national air quality standards for particle pollution: 

primary standards set limits to protect public health, including the health of "sensitive" 

populations such as asthmatics, children, and the elderly; secondary standards set limits to 

protect public welfare, including protection against visibility impairment, damage to animals, 

crops, vegetation, and buildings.

Human health risks of a gas-fired alternative are generally low, although Table 8-2 of the GEIS 

identifies cancer and emphysema as potential risks from the operation of the natural gas-fired 

plant. However, the current Federal and Minnesota State air emission standards adequately 

protect the occupational workers and the members of the public. Therefore, the NRC staff has 

adopted applicable Federal and state air quality regulations as the thresholds for determining 

the human health risks associated with the operation of a new natural gas-fired power plant.

Natural gas-fired plants emit total suspended particulates mostly in a form of PM10. Fine particle 

pollution, especially particulate matter less than 2.5 μm in diameter (PM2.5), is linked to a variety 

of lung and cardiovascular diseases (EPA 2008). As part of the air permit application, the Best 

Available Control Technology analysis would determine the best method necessary to reduce 

emissions.

NOx emissions contribute to formation of ground-level ozone (O3) and participate in chemical 

reactions with other air particles to form nitrate particles, acid aerosols, and NO2, all of which are 

known to have adverse impacts on human health. If the new natural gas-fired plant employed

the latest technology for NOx emission control systems and implemented emission-trading or 

offset requirements, it would not contribute to an overall increase in NOx in the region. The NRC 

staff concludes that the impacts on human health of the onsite and offsite natural gas-fired 

alternative are likely to be SMALL.
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8.1.6 Socioeconomics

The GEIS generically evaluates the impacts of operations on land use both onsite and offsite.

The analysis of land use impacts focuses on the amount of land area that would be affected by 

the construction and operation of a natural gas-fired power plant at the PINGP 1 and 2 site and 

at an alternate site. Land use impacts would vary depending on where the plant is located and 

whether construction would take place on undeveloped land or within a previously disturbed 

(brownfield) site.

Land Use

As stated in the introduction of the natural gas-fired alternative, NSP indicated that 

approximately 41 ac (17 ha) would be necessary to support a natural gas-fired alternative 

capable of replacing PINGP 1 and 2. There is a possibility that additional land would be 

necessary for a buffer zone around plant structures or to support transmission lines at an 

alternate site and gas pipelines at both PINGP 1 and 2 and at an alternate site. Land use 

impacts from construction would be SMALL. Impacts could be further reduced if the power plant 

is co-located at an alternate site with another generating station or on a previously industrial site 

like PINGP 1 and 2.

In addition to onsite land requirements, land would be required offsite for natural gas wells and 

collection stations. The GEIS estimates that 3600 ac (1500 ha) would be required for wells, 

collection stations, and pipelines to bring the gas to a 1000-MWe generating facility. If this land 

requirement were scaled with generating capacity, an alternative to PINGP 1 and 2 could 

require approximately 4220 ac (1710 ha). Most of this land requirement would occur on land 

where gas extraction already occurs. In addition, some natural gas could come from outside of 

the U.S. and be delivered as liquefied gas.

The elimination of uranium fuel for PINGP 1 and 2 could partially offset offsite land 

requirements. In the GEIS, the NRC staff estimated that, if the need for uranium fuel were 

eliminated, approximately 1000 ac (405 ha) would not be needed for mining and processing 

uranium for the operating life of a 1000-MWe nuclear power plant. For PINGP 1 and 2, roughly 

1044 ac (423 ha) of uranium mining area would no longer be needed.

Overall land use impacts from a gas-fired power plant would be SMALL to MODERATE, 

depending on whether the gas-fired plant is located at the PINGP 1 and 2 site, local land use if 

the gas-fired plant is located at a different site, the percentage of gas extraction that takes place 

where gas extraction already occurs, and the availability of previously disturbed land near the 

proposed site.

Socioeconomic impacts are defined in terms of changes to the demographic and economic 

characteristics and social conditions of a region. For example, the number of jobs created by the 

construction and operation of a new natural gas-fired power plant could affect regional 

employment, income, and expenditures. Job creation is characterized in two ways: (1) 

construction-related jobs, which are transient, short in duration, and less likely to have a longterm socioeconomic impact; and (2) operation-related jobs in support of power plant operations, 

which have the greater potential for permanent, long-term socioeconomic impacts. Workforce 

requirements of power plant construction and operations for the natural gas-fired power plant 

alternative were examined in order to measure their possible effect on current socioeconomic 

conditions.

Socioeconomics
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NSP projected a maximum construction workforce of 629 (NMC 2008). The GEIS projects a 

workforce of 1200 to 2500 for a 1000-MWe plant (when extrapolated, a lower-end workforce of 

approximately 1400 for an 1125-MWe plant).

During construction, the communities surrounding the power plant site would experience 

increased demand for rental housing and public services, although these effects would be 

moderated if the power plant construction site is located near an urban area with many skilled 

workers. The relative economic effect of these workers on local economy and tax base would 

vary over time.

After construction, local communities may be temporarily affected by the loss of construction 

jobs and associated loss in demand for business services, and the rental housing market could 

experience increased vacancies and decreased prices. As noted in the GEIS, the 

socioeconomic impacts at a rural construction site could be larger than at an urban site, 

because of an increased likelihood that the workforce would have to move to be closer to the 

construction site. The impact of construction on socioeconomic conditions could range from 

SMALL to MODERATE depending on the socioeconomic characteristics of communities near 

the new gas-fired plant. The socioeconomic impacts of power plant construction could be 

reduced if the power plant is located near an urban area with many skilled workers. Impacts are 

likely to be SMALL at the current plant site given proximity to areas with skilled workers. 

NSP estimated a gas-fired power plant operations workforce of 35 (NMC 2008), or up to 166 

workers based on an extrapolated GEIS estimates. The NSP estimate appears reasonable and 

is consistent with trends toward lowering labor costs by reducing the size of power plant 

operations workforces. Depending on location, the small number of operations workers would 

likely not have a noticeable effect on socioeconomic conditions in the region.

This alternative would lead to the shutdown of the PINGP 1 and 2. This shutdown would have 

an impact on socioeconomic conditions in the region. Plant shutdown would eliminate 

approximately 700 jobs and would reduce tax revenue in the region. The loss of these 

contributions, which may not occur until after decommissioning, could have a SMALL to 

MODERATE local impact. Appendix J to NUREG-0586, Supplement 1 (NRC 2002) discusses

the potential socioeconomic impacts of plant decommissioning.

Overall, socioeconomic impacts associated with operation of a gas-fired power plant would be 

SMALL to MODERATE.

Construction and operation of a two unit natural gas-fired power plant would increase the 

number of vehicles on roads in the vicinity of the plant. During construction, cars and trucks 

would deliver workers, materials, and equipment to the worksite. The increase in vehicular traffic 

would peak during shift changes resulting in temporary levels of service impacts and delays at 

intersections. Pipeline construction and modification to existing natural gas pipeline systems 

could also have an impact.

Transportation

During plant operations, transportation impacts would almost disappear. According to NSP, 

approximately 35 workers would be needed to operate the gas-fired power plant. Because fuel 

is transported by pipeline, most transportation infrastructure would experience little increased 

use from plant operations. 

The gas-fired alternative would have a SMALL impact on transportation conditions in the region 

around the PINGP 1 and 2 site and a SMALL to MODERATE impact at an alternate site, 

depending on the location of the alternative site and what the roadway capacity and average 

daily volumes are at that site location.
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Aesthetic resources are the natural and manmade features that give a particular landscape its 

character and aesthetic quality. The aesthetics impact analysis focuses on the degree of 

contrast between the power plant and the surrounding landscape and the visibility of the power 

plant.

Aesthetics

The two gas-fired units could be approximately 100 ft (30 m) tall, with two exhaust stacks at 

least 175 ft (53 m) tall or taller depending on the topography at an alternate site. Some 

structures may require aircraft warning lights. If the plant is located near the existing PINGP 1 

and 2 site some of the impacts may be reduced because higher elevations and vegetation along 

the Mississippi river valley could make it difficult to see or hear the plant outside of the river 

valley. Power plant infrastructure would generally be smaller and less noticeable than PINGP 1

and 2 containments. Mechanical draft cooling towers would generate condensate plumes and 

operational noise, though smaller cooling requirements will mean smaller (or fewer) towers, 

which should generate less noise and smaller plumes than the existing facility. Noise during 

power plant operations would be limited to industrial processes and communications. Pipelines 

delivering natural gas fuel could be audible off site near compressors.

In addition to new power plant structures, the alternate plant site may require the construction of 

transmission lines and natural gas pipelines. Although the pipelines would be buried, the 

transmission lines would have a lasting visual effect on the landscape.

In general, aesthetic changes would be limited to the immediate vicinity of PINGP 1 and 2 or an 

alternate site. The gas-fired alternative would have a SMALL impact on aesthetics if the location 

was at the existing PINGP 1 and 2 site, and a possible SMALL to MODERATE impact of the 

location was at a different site location. If a new site is selected for the gas-fired alternative, 

impacts to aesthetics could be reduced by choosing a site where a plant is already located and 

where transmission lines are already in place.

Historic property, as defined in 36 CFR Part 800, means any prehistoric or historic district, site, 

building, structure, or object included in, or eligible for inclusion in, the National Register of 

Historic Places (NRHP) maintained by the Secretary of the Interior. This term includes artifacts, 

records, and remains that are related to and located within such properties. Historic and 

archaeological resources are the indications of human occupation and use of the landscape as 

defined and protected by a series of Federal laws, regulations, and guidelines. Prehistoric 

resources are physical remains of human activities that predate written records; they generally 

consist of artifacts that may alone or collectively yield information about the past. Historic 

resources consist of physical remains that postdate the emergence of written records; in the 

U.S., they are architectural structures or districts, archaeological objects, and archaeological 

features dating from 1492 and later. Ordinarily, sites less than 50 years old are not considered 

eligible for listing on the NRHP, but exceptions can be made for such properties if they are of 

particular importance, such as structures associated with the development of nuclear power 

(e.g., Shippingport Atomic Power Station) or Cold War themes. American Indian resources are 

sites, areas, and materials important to American Indians for religious or heritage reasons. Such 

resources may include geographic features, plants, animals, cemeteries, battlefields, trails, and

other environmental features. The power plant site and adjacent areas that could potentially be 

disturbed by the construction and operation of alternative power plants constitutes the area of 

potential effect (APE).

Historic and Archaeological Resources

Chapter 2 of this SEIS discusses the affected environment in terms of cultural and archeological 

resources in the vicinity of the PINGP 1 and 2 site. As noted in Chapter 4, impacts to historic 
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and archeological resources are a MODERATE impact; therefore, impacts from a gas-fired plant 

located on the PINGP 1 and 2 site could be MODERATE. However, these impacts could be 

mitigated if the utility commitments discussed in Chapter 4 of this SEIS were implemented for 

the gas-fired plant as well. Impacts to historic and archeological resources from a gas-fired plant 

located at an alternative site would vary depending on the location of the site. Given the 

relatively small amount of land required for this alternative, and the commitments discussed in 

Chapter 4, impacts to historic and archeological resources would be SMALL to MODERATE.

The following information is provided by the Prairie Island Indian Community.

Depending on the location and timing of this alternative, there could be 

MODERATE impacts to archaeological sites within the boundaries of the PINGP. 

For instance, if this alternative was implemented before the PINGP was 

decommissioned, there may be impacts to archaeological sites, as the facility 

would require approximately 40 acres of land that has not been previously 

developed. It is presumed that the existing PINGP infrastructure (parking lots, 

buildings, etc.) would be needed until the PINGP was fully decommissioned. 

Therefore, this alternative would need land that had not been previously 

disturbed and likely to contain archaeological resources. 

This alternative would have less or no impact on archaeological sites if it were to be 

developed after PINGP decommissioning, as the entire former site could be utilized. 

The NRC would have to ensure that archaeological sites are not impacted during 

decommissioning. As well, the developer of the gas-fired alternative would have to 

ensure that all archaeological sites were protected during construction.

Section 4.9.7 of this SEIS addresses the purpose and content of an environmental justice 

impact analysis. In this section, the NRC staff evaluates the potential for disproportionately high 

and adverse human health and environmental effects on minority and low-income populations 

that could result from the construction and operation of a new natural gas-fired power plant.

Environmental Justice

Minority and low-income populations could be affected by the construction and operation of a 

new natural gas-fired power plant. Some of these effects have been identified in other resource 

areas discussed in this section. The extent of disproportionate effect is difficult to determine 

since it would depend on the location of the natural gas-fired power plant. If the natural gas-fired 

plant were located on the PINGP 1 and 2 site, the PIIC would be disproportionately affected. In 

addition, increased demand for rental housing during construction could disproportionately 

affect low-income populations. However, demand for rental housing could be mitigated if the 

alternate plant site is constructed near a metropolitan area.

Impacts on minority and low-income populations from the construction and operation of a 

natural gas-fired power plant alternative could range from SMALL to MODERATE. Because an 

on-site gas-fired plant located on the current PINGP 1 and 2 site would only require a small 

number of workers, effects are unlikely to be adverse, and any that are disproportionate are 

likely to be SMALL. An off-site gas-fired plant could have SMALL to MODERATE environmental 

justice impacts; however these effects could be reduced if the plant was located near a 

metropolitan area or on a previously disturbed site. 

The following information is provided by the Prairie Island Indian Community.

As stated above, if the 1000 MWe gas-fired plant were to be located within the 

boundaries of the PINGP, the Prairie Island Indian Community would be 

disproportionately impacted. The Tribe believes that the MODERATE air quality 
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impacts would also have a MODERATE impact on the health of tribal members, 

particularly the children and elders, who would be reside next to the gas-fired 

plant. The winds do not always blow from the west to the east (i.e., away from 

the community). Our research has shown that the often prevailing winds are out 

of the S, SE, SW, or E. In addition, because of our location within the floodplain 

of the Mississippi River valley, there are days when we experience air inversions. 

The result of these air inversions is that particulate matter is trapped closer to the 

ground and not dispersed in the atmosphere, thereby potentially impacting 

human health.

There would be a significant increase in the number of vehicles driving through 

the community, as part of constructing the 1000 MWe gas-fired plant and, 

possibly, decommissioning the PINGP. This also has air quality implications, 

safety concerns related to increases in traffic burdens for tribal members, 

employees and guests at the Treasure Island Resort and Casino, and noise 

impacts 

In addition, if the PINGP were to be decommissioned, the Independent Spent 

Fuel Storage Installation (ISFSI) would still be operational. Depending on when 

the PINGP shutdown, there could be between 68 and 98 dry casks stranded 

indefinitely on Prairie Island. The 2003 Settlement agreement between the tribe 

and NSP, related to the dry cask storage, would still be in effect.

8.1.7 Waste Management

Spent selective catalytic reduction catalysts, which are used to control NOx emissions from the 

natural gas-fired plants, would make up the majority of the waste generated by this alternative 

However, spent catalyst is usually either regenerated for reuse or the components are recycled

for other uses. 

Land clearing and other construction activities, associated with the construction of the gas-fired 

plant would generate waste that can be recycled, disposed of onsite, or shipped to an offsite 

waste disposal facility. If the alternative were constructed at the PINGP 1 and 2 site or any 

previously disturbed site, the amounts of waste produced by land-clearing during construction 

would be reduced.

In the GEIS, NRC staff concluded that a natural gas-fired alternative located either onsite or 

offsite of an existing nuclear facility would generate minimal waste and that the waste impacts 

would be SMALL.

8.2 Combination Alternative 1

In this section, we evaluate the environmental impacts of an alternative that makes use of 

several different means of power generation as well as power conservation. This alternative 

includes a 400-MWe gas-fired unit on the existing PINGP 1 and 2 site, 300 MWe of wind power 

capacity offsite, 100 MWe of wood-fired generation offsite, and 250 MWe of electricity offset by 

conservation measures. 

The gas-fired portion of this alternative would be similar in function to the gas-fired alternative in 

Section 8.1. It would also use combined-cycle technology, but would be slightly more efficient 

than the units used in Section 8.1. An existing 400-MWe combined-cycle unit currently available 

from GE (GE 2007) operates at 5690 Btu/kWh, or 60 percent thermal efficiency. 
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Wind power portions of this alternative would likely be located offsite, as insufficient land is 

available on the PINGP 1 and 2 site to support a wind-powered alternative. While wind power 

installations require substantial amounts of land to achieve adequate turbine spacing, only a 

small amount of land is actually disturbed during construction and occupied by turbines and 

infrastructure during operation. In many areas, surrounding land can be used for agriculture. 

Wood-fired portions of this alternative would also likely be located offsite, and would likely 

consist of a number of small (approximately 50-MWe) installations. Wood-fired generation tends 

to be most economical when located near wood resources, especially mills or areas that 

generate forest wastes during logging operations. Generation fired by wood wastes tends to be 

more environmentally benign than installations fired by wood harvested specifically for power 

generation. For purposes of this analysis, the NRC staff has assumed that wood waste would 

power the wood-fired portion of this alternative. Construction impacts from a wood waste facility 

would likely be similar to an equivalently-sized coal-fired facility.

Energy conservation (or energy efficiency), while not a generation alternative per se, is a 

component of established energy policy in Minnesota. The Next Generation Energy Act of 2007 

established a goal of a 1.5 percent annual reduction in retail electric sales for utilities and 

associations in Minnesota. As noted in Section 8.4.3, this reduction in energy consumption 

would not be sufficient to offset the full capacity of PINGP 1 and 2 by the time its licenses 

expire, but it is sufficient to contribute to a combination alternative. The GEIS notes that 

environmental impacts of conservation tend not be well-established.

Table 8-2. Summary of Environmental Impacts of Combination Alternative 1 Compared to 

Continued PINGP 1 and 2 Operation

Combination Alternative 1 Continued PINGP 1 and 

2 Operation

Air Quality MODERATE SMALL

Ground Water SMALL SMALL

Surface Water SMALL to MODERATE SMALL

Ecology MODERATE SMALL

Human Health MODERATE SMALL

Socioeconomics SMALL to LARGE SMALL TO MODERATE

Waste Management SMALL SMALL

8.2.1 Air Quality

As discussed in Section 8.1.1, a new gas-fired generating plant, proposed to be built in 

Goodhue County, would require a New Source Review and a Title V permit under the CAA and 

would need to submit an Air Emission Risk Analysis as required by the MPCA and a 

Greenhouse Gas Emissions Evaluation as required by 40 CFR Part 70. As discussed in Section 

8.1.1, it is unlikely that Protection of Visibility provision (40 CFR Part 51, Subpart P) 

requirements would apply as the nearest Federal Class I areas in Minnesota would not be 

significantly affected due to the distance from the site. 

The projected emissions from the one-unit natural gas-fired component of the alternative based 

on published EIA data, EPA emission factors, performance characteristics for this alternative,

and implemented emission controls are as follows:
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Sulfur dioxide (SO2) – 30.01 tons (27.23 MT) per year;

Nitrogen oxides (NOx) – 96.21 tons (87.28 MT) per year;

Carbon monoxide (CO) – 20 tons (18.15 MT) per year;

Total suspended particles/PM10– 16.77 tons (15.21 MT) per year;

Carbon dioxide (CO2) – 1,032,495.72 tons (936,680.12 MT) per year.

The new natural gas-fired plant would have to comply with Title IV of the CAA reduction 

requirements for SO2 and NOx. These compounds are precursors of acid rain and are major 

contributors to reduced visibility. Title IV establishes maximum SO2 and NOx emission rate from 

the existing plants and a system of the SO2 emission allowances that can be used, sold’ or 

saved for future use by the new plants.

As stated above, the new natural gas-fired alternative would produce 30.01 tons (27.23 MT) per 

year of SO2 and 96.21 tons (87.28 MT) per year of NOx based on the use of the dry low NOx

combustion technology and the use of the selective catalytic reduction, which allow significant 

reduction of NOx emissions. 

The new plant would be subjected to the continuous monitoring requirements of SO2 and NOx

specified in 40 CFR Part 75 and CO specified in 40 CFR Part 60. The natural gas-fired plant as 

a part of this alternative would emit 1,032,495.72 tons (936,680.12 MT) per year of unregulated 

CO2 emissions. Minnesota Statute §216H stipulates greenhouse gas emissions reporting 

requirements and statewide adoption of climate change action plan, which requires a reduction 

in greenhouse gases. 

This alternative would emit 16.77 tons (15.21 MT) per year of PM10 (40 CFR 50.6a). All 

suspended particles emitted by the gas-fired portion of this alternative are PM10. 

 The projected emissions from the wood-fired component of this combination alternative based 

on published EIA data, EPA emission factor, performance characteristics for this alternative,

and implemented emission controls are as follows:

Sulfur dioxide (SO2) – 124.10 tons (112.58 MT) per year;

Nitrogen oxides (NOx) – 608.09 tons (551.66 MT) per year;

Carbon monoxide (CO) – 744.60 tons (675.50 MT) per year;

TSP (filtered) – 496.40 tons (450.33 MT) per year;

PM10 (filtered) – 367.34 tons (333.25 MT) per year;

PM2.5 (filtered) – 322.66 tons (292.72 MT) per year;

Carbon dioxide (CO2) – 967,980 tons (878,151.46 MT) per year.

The wood-fired combustion facility would be subject to Federal and state air emissions 

regulations described above for the natural gas-fired component of this alternative. This plant 

would also produce 496.55 tons (450.33 MT) per year of PM10 (40 CFR §50.6a) and 322.66 

tons (292.72 MT) per year of PM2.5, which have to meet the national primary and secondary 

ambient air quality standards (40 CFR §50.7a).

There would be no emissions from the wind-powered component of this combination alternative.

The energy conservation component of this alternative reduces direct fuel use and causes 

reduction in environmental emissions from workers’ vehicle exhaust, plant fuel cycles, and 

operation and maintenance of the plant. Improvements in efficiency may also reduce 

consumption of fuels that are used for space and water heating purposes. 
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Activities associated with the construction of the new natural gas-fired plant onsite or offsite of 

PINGP 1 and 2 as well as construction of a wood-fired combustion facility and a wind farm 

would cause some additional air effects as a result of equipment emissions and fugitive dust

from operation of the earth-moving and material handling equipment. Exhaust from workers’ 

vehicles and motorized construction equipment would be temporary. If construction crews 

employ dust control practices, impacts from fugitive dust could be minimized. The NRC staff 

concludes that the impact of vehicle exhaust emissions and fugitive dust from operation of the 

earth-moving and material handling equipment would be SMALL.

The overall air quality impacts from the implementation of this combination alternative would be 

MODERATE. 

8.2.2 Ground Water Use and Quality

The use of ground water for an onsite gas-fired unit would likely be limited to supply wells for 

drinking water, landscaping, non-condenser cooling, and filtered service water. The existing 

permitted onsite supply wells could continue to be used with a range of total average discharge 

from 75 to 100 gpm. The impact on ground water use and quality would be SMALL. The offsite 

wind farm and biomass combustion units would also use a limited amount of ground water.

Water appropriation permits would be required, but the impact on ground water use and quality

in the area would also be SMALL.

8.2.3 Surface Water Use and Quality

An onsite 400-MWe gas-fired unit would use less than half the amount of surface water from the 

Mississippi River as the current plant. The consumptive use of surface water would be SMALL

compared to the average flow of the river in the vicinity of PINGP 1 and 2, and the impact would 

be SMALL. The offsite biomass combustion units, totaling 100-MWe, would also have relatively 

small consumptive use of surface water. The waste water discharge from the biomass plant, 

including runoff, would have to be permitted by the MPCA, and the impact on receiving waters 

could potentially be MODERATE depending on the location of the plant.

8.2.4 Aquatic and Terrestrial Ecology

Impacts to aquatic ecology from this combination alternative would be minimal, as the 

consumptive water use of a natural gas-fired plant would be significantly less than the water 

consumption of PINGP 1 and 2. Additionally, the onsite natural gas-fired plant could use parts of 

the existing cooling system, which would reduce potential impacts to aquatic resources. Impacts 

of the offsite wind and biomass facilities would depend on location and the ecology of the site, 

but would likely be minimal. Construction in a previously disturbed area would have lower

impacts to the aquatic resources than construction in an undisturbed area. Energy conservation 

would have no impacts on aquatic ecology. Overall, the impacts to aquatic resources from this 

combination of alternatives would be SMALL.

As indicated in previous sections, the onsite one-unit natural gas-fired component of this 

alternative will require 16 ac (7 ha) of land, according to calculations presented in the ER (NMC 

2008). Impacts to terrestrial ecology from this portion of the alternative will be minor because 

the selected site has been previously disturbed. Buildings and structures associated with PINGP 

1 and 2 occupy approximately 60 ac (24 ha) of the site (NMC 2008); therefore, some areas of 

previously disturbed land may return to natural habitat as a result of this alternative because 

less land would be required than is currently in use for PINGP 1 and 2. Buffer areas and 

surrounding wetland habitat on or in the vicinity of the site may remain undeveloped and would 

continue to provide habitat for terrestrial species, though site lighting, noise, and activities may 
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degrade the value of these neighboring habitats. Construction of additional transmission line 

ROWs is unlikely because existing transmission capacity at the PINGP 1 and 2 site could be 

used. Any lengthy pipelines or additional roads on undisturbed or less-disturbed areas could 

adversely impact terrestrial ecology by fragmenting or destroying habitats. However, a pipelined 

fuel source and a small workforce would help to minimize the need for additional transportation 

infrastructure. Gas extraction and collection will also affect terrestrial ecology in offsite gas 

fields, although much of this land is likely already disturbed by gas extraction, and the 

incremental effects of this alternative on gas field terrestrial ecology are difficult to gauge.

The offsite two-unit biomass combustion component of this alternative will require 192 ac (78

ha) of land, according to calculations presented in the GEIS for coal-fired units. The GEIS 

estimates that the overall level of construction impacts from biomass combustion unit impacts 

are expected to be similar to coal-fired units of similar size. Because biomass combustion units 

require large areas for buildings and structures associated with fuel and processing, 

construction activities may fragment or destroy natural habitats. Construction of additional 

transmission line ROWs, railways, or roads would further fragment natural habitat beyond the 

192-ac (78-ha) site. Impacts from logging slash and forest thinning to provide fuel for this 

alterative may alter terrestrial habitats by allowing edge effects to permeate a greater portion of 

the disturbed land, which may change the abundance and distribution of interior species and 

increase the area’s susceptibility to invasive species. Deposition of air pollutants may affect 

terrestrial ecology, but are expected to be minimal. Ash disposal is not likely to adversely affect 

terrestrial ecology and may enrich soils if deposited at lower pH levels.

The offsite wind power installation component of this alternative will require approximately 

64,000 ac (25,900 ha) of land, of which approximately 250 ac (100 ha) would be used for actual 

towers and infrastructure. Construction disturbances associated with the wind power installation 

may significantly impact terrestrial ecology, and some erosion and sedimentation may result. 

However, because the wind power installations would be dispersed among a total area of 

approximately 64,000 ac (25,900 ha), and the potential exists to spread the installations among 

several locations, wildlife corridors resulting from construction and undisturbed buffer zones 

would continue to provide habitat for terrestrial species. No air pollutant deposition would result 

from this component of the alternative.

Impacts to terrestrial resources from this combination of alternatives at both the PINGP 1 and 2 

site and offsite locations are expected to be MODERATE.

8.2.5 Human Health

EPA establishes NAAQS for six criteria pollutants (40 CFR Part 50) under the CAA. The CAA

recognizes two types of national air quality standards for particle pollution: primary standards 

set limits to protect public health, including the health of "sensitive" populations such as 

asthmatics, children, and the elderly; and secondary standards set limits to protect public 

welfare, including protection against visibility impairment, damage to animals, crops, vegetation, 

and buildings. 

CO, NOx, and particulate matter are the major emissions during operation of the wood-fired 

plant, as concluded in the GEIS. In Table 8-2 of the GEIS, the NRC staff identified that 

occupational risks are high (same as agricultural) during the operation of the wood-fired

electricity generating plant. However, the current Federal and state air emission standards 

adequately protect the occupational workers and the members of the public. Therefore, the 

NRC staff has adopted applicable Federal and state air quality regulations as the thresholds for 

determining the human health risks associated with the operation of a new natural gas-fired 

power plant. 
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Wood-fired plants would emit PM10 and PM2.5. Fine particle pollution, PM2.5, is linked to a variety 

of lung and cardiovascular diseases (EPA 2008). Industrial fabric filters or electrostatic 

precipitators could be used to control and significantly minimize emissions.

NOx emissions contribute to formation of ground-level ozone and participate in chemical 

reactions with other air particles to form nitrates, acid aerosols, and NO2, which are known to 

have adverse impacts on human health. The new natural gas-fired plant would have latest 

technology NOx emission control systems installed and implemented emission-trading or offset 

requirements, and therefore, a new plant would not increase overall NOx in the region. The NRC 

staff concludes that the impacts on human health of this combination alternative are likely to be 

MODERATE.

8.2.6 Socioeconomics

The GEIS generically evaluates the impacts of nuclear power plant operations on land use both 

onsite and offsite of a power plant site. The analysis of land use impacts for this combination 

alternative focuses on the amount of land area that would be affected by the construction and 

operation of a single natural gas-fired unit power plant at PINGP 1 and 2 and an offsite wind and 

biomass energy generating power plant.

Land Use

Land use impacts for the gas-fired component of this alternative would take place on the 

existing PINGP 1 and 2 site and will likely require no additional land. Most land on the PINGP 1 

and 2 site has been previously disturbed. Construction impacts could be further reduced by 

reusing the cooling towers and other existing support facilities, like the switchyard. Therefore, 

land use impacts for the construction of the gas-fired portion of this alternative would be SMALL. 

In addition to onsite land requirements for the gas-fired plant, land would be required offsite for 

natural gas wells and collection stations. The GEIS estimates that 3600 ac (1500 ha) would be 

required for wells, collection stations, and pipelines to bring the gas to a 1000-MWe generating 

facility. If this land requirement were scaled directly with generating capacity for this alternative, 

up to 1500 ac (600 ha) of land could be required. Most of this land requirement would occur on 

land where gas extraction already occurs. In addition, some natural gas could come from 

outside of the U.S. and be delivered as liquefied gas. Effects from gas extraction are generally 

small, as most land around a gas extraction site would remain undisturbed, except for roads and 

collection pipe network. Therefore, impacts to land use from offsite gas wells and collection 

stations would be SMALL.

The wind farm component of this combination alternative would produce 300 MWe of electricity 

and require approximately 64,000 ac (26,000 ha) spread over several locations. Turbine towers 

and infrastructure would only occupy roughly 5% of this area, while the remainder would be 

available for complementary land uses, like agriculture. The wood-fired biomass component 

would produce 100 MWe of electricity and require 190 ac (78 ha) for plant facilities, though 

wood fuel may be collected over a much larger area. Because the wood-fired portion of this 

alternative uses wood waste for fuel, the wood-fired plants should have little other effect on land 

use.

Regarding the conservation portion of this alternative, quickly replacing and disposing of old 

inefficient equipment could generate waste material and potentially increase the size of landfills.

Roughly 4 to 5 years remain, respectively, before PINGP 1 and 2 licenses expire, thus some 

equipment may be replaced prior to the end of its expected life span in exchange for more 

efficient equipment, depending on how authorities ultimately structure a conservation program. 

Some programs may provide incentives for replacing less efficient equipment. In general, 
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though, the cost of replacements and the average life of electrical equipment should allow for a 

somewhat gradual replacement process that favors replacement of older or shorter-lived 

equipment by more efficient equipment as it fails (especially in the case of frequently replaced 

items, like light bulbs). In addition, many items (like home appliances or industrial items) have 

substantial recycling value and would likely not be disposed of in landfills.

The elimination of uranium fuel for PINGP 1 and 2 could partially offset this alternative’s offsite 

land requirements. In the GEIS, the NRC staff estimated that approximately 1000 ac (405 ha) 

would not be needed for mining and processing uranium during the operating life of a 1000-

MWe nuclear power plant. For PINGP 1 and 2, roughly 1044 ac (423 ha) of uranium mining 

area would no longer be needed.

Overall impacts to land use from this combination alternative would be SMALL to LARGE,

depending on the locations selected for wind farms and the location for offsite gas wells and 

collection stations. Some of these impacts could be reduced by locating the wind farms on 

previously disturbed areas, or locations that have existing land uses—like agriculture—that can 

coexist with wind farms. Land use impacts can also be minimized by using existing transmission 

lines.

As previously discussed, socioeconomic impacts are defined in terms of changes to the 

demographic and economic characteristics and social conditions of a region. For example, the 

number of jobs created by the construction and operation of a new single natural gas-fired 

power plant, wind farm, and wood-fired biomass generating plant could affect regional 

employment, income, and expenditures. Job creation is characterized in two ways: (1) 

construction-related jobs, which are transient, short in duration, and less likely to have a longterm socioeconomic impact; and (2) operation-related jobs in support of power plant operations, 

which have the greater potential for permanent, long-term socioeconomic impacts. Workforce 

requirements of power plant construction and operations for this combination alternative were 

determined in order to measure their possible effect on current socioeconomic conditions.

Socioeconomics

NSP projected a peak construction workforce of 237 workers for the gas-fired plant (NMC 

2008). The GEIS projects a workforce of 1200 to 2500 for a 1000-MWe plant (when 

extrapolated, a workforce of approximately 500 for a 400-MWe plant). NRC staff will use the 

NSP estimate of 237 workers for reasons discussed in 8.1.

This alternative would lead to the shutdown of the PINGP 1 and 2. This shutdown would have 

an impact on socioeconomic conditions in the region. Plant shutdown would eliminate 

approximately 700 jobs and would reduce tax revenue in the region. The loss of these 

contributions, which may not occur until after decommissioning, could have a SMALL to 

MODERATE local impact. Appendix J to NUREG-0586, Supplement 1 (NRC 2002) discusses

the potential socioeconomic impacts of plant decommissioning.

Additional estimated construction workforce requirements for this combination alternative would 

include 300 workers for the wind farm and 133 to 278 workers for the wood-fired biomass 

energy plant. The number of additional workers would cause a short-term increase in the 

demand for services and temporary (rental) housing in the region around the construction sites.

After construction of the wind farm and wood-fired plant, and depending on the size of the 

affected communities, some local communities may be temporarily affected by the loss of the 

construction jobs and associated loss in demand for business services. The local rental housing 

markets could also experience increased vacancies and decreased prices. The impact of 

construction from the wind farm and the wood-fired plant on socioeconomic conditions would be 

SMALL, given the relatively low levels of employment associated with the wind power and wood 
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waste components of this alternative. Further, employment effects from the wind power portion 

of this alternative are likely to be spread over a larger area, as the wind farms may be 

constructed in more than one location.

Following construction, a single unit gas-fired combination alternative could provide up to 13 

jobs, based on NSP estimates, or up to 63 jobs based on an extrapolated estimate from the 

GEIS. Additional estimated operations workforce requirements for this combination alternative 

would include 50 workers for the wind farm and 28 workers for the wood-fired biomass energy 

plant. Given the small numbers of operations workers at these facilities, socioeconomic impacts 

associated with the operation of the natural gas-fired power plant at PINGP 1 and 2, as well as 

the wind farm and wood-fired biomass energy plant, would be SMALL.

Socioeconomic effects of an energy efficiency program would be SMALL. As noted in the GEIS, 

the program would likely employ additional workers. Lower-income families could benefit from 

weatherization and insulation programs. This effect would be greater than the effect for the 

general population because low-income households experience home energy burdens more 

than four times larger than the average household (OMB 2007).

Overall, operational impacts to socioeconomics for this combination alternative would be 

SMALL, due to the small numbers of additional workers required to run the gas-fired, wind farm, 

and wood-fired portions of the alternative.

Construction and operation of a natural gas-fired power plant, wind farm, and wood-fired 

biomass generating plant would increase the number of vehicles on roads in the vicinity of these 

facilities. During construction, cars and trucks would deliver workers, materials, and equipment 

to the worksites. The increase in vehicular traffic would peak during shift changes resulting in 

temporary levels of service impacts and delays at intersections. Transporting components of 

wind turbines could have a noticeable impact, but are likely to be spread over a large area.

Pipeline construction and modification to existing natural gas pipeline systems could also have 

an impact. Any transportation effects from the energy conservation portion of this alternative 

would be widely distributed across the state, and would be SMALL to MODERATE.

Transportation

During plant operations, transportation impacts would almost disappear, excepting 

transportation of wood waste to the wood-fired power plants. Given the small numbers of 

operations workers at these facilities, overall operational impacts on transportation associated 

with this combination alternative would be SMALL.

As previously discussed, aesthetic resources are the natural and manmade features that give a 

particular landscape its character and aesthetic quality. The aesthetics impact analysis focuses 

on the degree of contrast between the components of this alternative and the surrounding 

landscape, as well as the aesthetic value of the surrounding landscape (e.g., areas near parks 

or recreation areas may be more sensitive).

Aesthetics

A single natural gas-fired unit located at PINGP 1 and 2 could be approximately 100 ft (30 m) 

tall, with an exhaust stack of at least 175 ft (53 m) tall. The impact would be moderated as 

higher elevations and vegetation along the Mississippi River valley could make it difficult to see 

or hear the power plant outside of the river valley. Power plant infrastructure would generally be 

smaller and less noticeable than PINGP 1 and 2 containment structures. The mechanical 

cooling tower or towers–much smaller than the existing onsite towers–would generate 

condensate plumes and operational noise. Noise during power plant operations would be limited 

to industrial processes and communications. In addition to the power plant structures, 
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construction of natural gas pipelines would have a short-term impact. Noise from the pipelines 

could be audible offsite near compressors.

The wind farm would have a greater aesthetic effect than the other elements of this combination 

alternative. Compared to a single power plant unit on 46 to 190 ac (19 to 77 ha), 500 turbines 

300 ft (100 m) in height spread over 64,000 ac (26,000 ha) acres could have significant impacts 

and, in the absence of larger topographic features, would be the major focus of viewer attention

as the most readily-visible structures around. In some areas where aesthetics are an important 

value, this may be objectionable.

Impacts from the energy conservation efficiency programs portion of this alternative would be 

SMALL. Because one of the PINGP 1 and 2 units would continue to operate, NSP would 

continue to use the existing onsite transmission lines, which would also support the onsite gasfired plant. Traffic to the existing PINGP 1 and 2 would decrease as would noise and emissions.

Some noise impacts could occur in instances of energy efficiency upgrades to major building 

systems, though this impact would be intermittent and short-lived, and would be scattered 

across many sites.

Most of the aesthetic impacts of this alternative would be a result of the wind farm. Overall the 

aesthetic impacts associated with this combination alternative would be categorized as 

MODERATE to LARGE if the wind farm is built at a site where aesthetics are an important 

element of the natural environment, and SMALL to MODERATE at other locations.

Historic property as defined in 36 CFR Part 800 is described above in Section 8.1.7.

Historic and Archaeological Resources

Chapter 2 of this SEIS discusses the affected environment in terms of cultural and archeological 

resources in the vicinity of the PINGP 1 and 2 site. Impacts to historic and archeological 

resources from a single unit gas-fired plant located on the PINGP 1 and 2 site could be 

MODERATE; however, these impacts could be mitigated if the utility commitments discussed in 

Chapter 4 of this SEIS are implemented for the gas-fired plant as well. Regarding the wind farm 

portion of this alternative, impacts to cultural and archeological resources could be significant; 

however, selecting a site where survey results indicate low sensitivity or where land has already 

been disturbed would minimize the overall impacts. Impacts to cultural and archeological 

resources from the conservation portion of this alternative would be minimal.

Overall, the impacts to historic and archeological resources could range from SMALL to 

MODERATE due mostly to uncertainty regarding the location of the wind farm, the effect on 

archeological resources at that site and whether the provisions discussed in 8.1.7 are used to 

determine the location of the offsite wind farm. 

The following information is provided by the Prairie Island Indian Community.

Depending on the location and timing of this alternative, there could possibly be 

impacts to archaeological sites within the boundaries of the PINGP. For 

instance, if this alternative was implemented before the PINGP was 

decommissioned, there may be impacts to archaeological sites, as the facility 

would require approximately 16 acres of land that has not been previously 

developed. It is presumed that the existing PINGP infrastructure (parking lots, 

buildings, etc.) would be needed until the PINGP was fully decommissioned. 

Therefore, this alternative would need land that had not been previously 

disturbed and likely to contain archaeological resources. 

This alternative would have less or no impact on archaeological sites if it were to 

be developed after PINGP decommissioning, as the entire former site could be 
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utilized. The NRC would have to ensure that archaeological sites are not 

impacted during decommissioning. As well, the developer of the gas-fired 

alternative would have to ensure that all archaeological sites were protected 

during construction.

Section 4.9.7 of this SEIS addresses the purpose and content of an environmental justice 

impact analysis. In this section, the NRC staff evaluates the potential for disproportionately high 

and adverse human health and environmental effects on minority and low-income populations 

that could result from the construction and operation of a combination alternative.

Environmental Justice

Minority and low-income populations could be affected by the construction and operation of a 

new natural gas-fired power plant, wind farm, and wood-fired biomass generating plant. Some 

of these effects have been identified in resource areas discussed earlier in this section. The 

extent of disproportionate effects is difficult to determine since it would depend on the location of 

the wind farm and wood-fired portions of this alternative. The PIIC, because it is located next to 

the PINGP 1 and 2 site, would be disproportionately affected from the gas-fired portion of this 

alternative because the location will be on the PINGP 1 and 2 site. Increased demand for rental 

housing during construction could disproportionately affect low-income populations. However, 

demand for rental housing could be mitigated if the gas-fired plant, wind farm, and wood-fired 

plants are constructed near a metropolitan area.

Weatherization programs could target low-income residents as a cost-effective energy efficiency 

option since low-income populations tend to spend a larger proportion of their incomes paying 

utility bills and also tend to live in structures that are less well insulated or have less-efficient 

appliances. According to the Office of Management and Budget, low income populations 

experience energy burdens more than four times as large as those of average households 

(OMB 2007). Impacts to minority and low-income populations from energy conservation 

efficiency programs portion of this alternative would be SMALL, though actual levels would 

depend on program design and enrollment.

Overall disproportionate and adverse impacts on minority and low-income populations from this 

combination alternative could range from SMALL to MODERATE depending on location of the 

off-site wind farm and wood-fired plants. Disproportionate effects such as increased demand for 

rental housing, are likely to be SMALL. The offsite wind farm and wood-fired plant could have 

MODERATE environmental justice impacts depending on location of the wind farm and woodfired plants.

The following information is provided by the Prairie Island Indian Community.

If the 400 MWe gas-fired plant were implemented within the boundaries of the 

PINGP, the Prairie Island Indian Community would be disproportionately 

affected. The Tribe believes that implementing the 400 MWe gas-fired plant will 

have a SMALL to MODERATE impact on air quality. In addition, these SMALL to 

MODERATE air quality impacts would also have a SMALL to MODERATE 

impact on the health of tribal members, particularly the children and elders, who 

would reside next to the 400 MWe gas-fired plant. As discussed in Section 8.1.7, 

the winds do not always blow from the west to the east (i.e., away from the 

community); often the prevailing winds are out of the S, SE, SW, or E. In 

addition, because of our location within the floodplain of the Mississippi River 

valley, there are days when we experience air inversions. The result of these air 

inversions is that particulate matter is trapped closer to the ground, and therefore 

not dispersed in the atmosphere. 
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There would be also be an increase in the number of vehicles driving through the 

community, as part of constructing the 400 MWe gas-fired plant and, possibly, 

decommissioning the PINGP. This also has air quality implications, additional 

traffic burdens for tribal members, employees and guests at the Treasure Island 

Resort and Casino, and noise impacts 

Like Alternative 1 (the gas-fired plant), if this alternative were implemented, the 

PINGP would be decommissioned and the Independent Spent Fuel Storage 

Installation (ISFSI) would still be operational. Depending on when the PINGP 

shut-down, there could be between 68 and 98 dry casks, stranded indefinitely on 

Prairie Island. The 2003 Settlement agreement between the tribe and NSPM, 

related to the dry cask storage, would still be in effect.

8.2.7 Waste Management

Spent selective catalytic reduction catalysts, which are used to control NOx emissions from the 

natural gas-fired plants, would be the primary waste component from the natural gas-fired 

alternative. 

Land clearing and other construction activities, associated with the construction of the gas-fired 

plant, would generate waste that can be recycled, disposed onsite, or shipped to an offsite 

waste disposal facility. If the alternative were constructed at the PINGP 1 and 2 site or any 

previously disturbed site, the amounts of wastes produced during land clearing would be 

reduced.

An increase in wastes would be experienced during installation or implementation of 

conservation measures such as appropriate disposal of old appliances, installation of control 

devices, and building modifications. Implementation of recycling programs would help to 

minimize the amount of generated waste.

As stated in the GEIS, the wood-fired component of this alternative would produce considerable 

amount of fly ash, which could be recycled for use as a beneficial fertilizer and soil conditioner.

The NRC staff concludes that overall waste impacts from this combination alternative are 

SMALL.

8.3 Combination Alternative 2

In this section, the NRC staff evaluates the environmental impacts that may occur from a 

combination of alternatives that includes continued operation of one PINGP 1 and 2 unit (either 

Unit 1 or Unit 2), 300 MWe of wind capacity, and 250 MWe of capacity offset by conservation. 

Impacts from wind and conservation portions of this alternative are the same as those 

addressed in Section 8.2 for Combination Alternative 1. Impacts from continued operation of 

one PINGP 1 and 2 unit will be similar to – though for some resource areas it may be less than 

– continued operation of PINGP 1 and 2. 
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Table 8-3. Summary of Environmental Impacts of Combination Alternative 2 Compared to 

Continued PINGP 1 and 2 Operation

Combination Alternative 2 Continued PINGP 1 and 2

Operation

Air Quality SMALL SMALL

Ground Water SMALL SMALL

Surface Water SMALL SMALL

Ecology SMALL SMALL

Human Health SMALL SMALL

Socioeconomics SMALL to LARGE SMALL TO MODERATE

Waste Management SMALL SMALL

8.3.1 Air Quality

The nuclear component of this combination alternative would have very limited effects on air 

quality and would produce less pollution than the natural gas-fired alternative or Combination 

Alternative 1. The major source of air pollution during continued operation of one PINGP 1 and 

2 unit would be testing and usage of the diesel generators, which run a permitted amount of 

time, ranging from several hours to several days per year.

The energy conservation component of the alternative reduces direct fuel use and causes 

reduction in environmental emissions from workers’ vehicle exhaust, plant fuel cycles, and 

operation and maintenance of the plant. Improvements in efficiency may also reduce 

consumption fuels that are used for space and water heating purposes. 

Exhaust emissions resulting from workers’ vehicles and motorized construction equipment in 

conjunction with construction of wind capacity would be temporary. Implementation of dust

control practices would minimize air quality impacts. Once constructed, no emissions would 

result from operation of the wind power units.

The NRC staff concludes that this combination alternative would have a SMALL overall impact 

on air quality.

8.3.2 Ground Water Use and Quality

Impacts on ground water use and quality of the continued operation of one PINGP 1 and 2 unit 

onsite would remain SMALL. The total use of ground water from the onsite wells would be less 

than the current annual use of approximately 115 gpm. The effects on ground water quality 

would also be SMALL because waste management and discharge procedures would be 

maintained as at present.

8.3.3 Surface Water Use and Quality

Operation of one PINGP 1 and 2 unit instead of two will reduce the consumptive use of surface 

water by approximately half. The impact of this reduced use of surface water would remain 

SMALL because the consumptive use would be negligible compared to flow in the Mississippi 

River near the PINGP 1 and 2 site, as it is with both units operating.
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8.3.4 Aquatic and Terrestrial Ecology

Impacts to aquatic ecology will be minimal, as the consumptive water use of a single PINGP 1 

and 2 unit would be less than the consumptive water use of a two-unit nuclear plant. Impacts of 

an offsite wind facilities on aquatic resources would depend on location and the ecology of the 

site, but would likely be minimal. Construction in a previously disturbed area would have less 

impacts to the aquatic resources than construction in an undisturbed area. Energy conservation 

would also result in less water withdrawal and discharge corresponding to a decreased demand 

for power generation. Overall, the impacts to aquatic resources from this combination of 

alternatives would be SMALL.

The continued operation of one PINGP 1 and 2 unit would result in no additional impacts to 

terrestrial resources than those discussed in Chapter 4 of this SEIS, as no additional land 

disturbances onsite or offsite would occur. The Unit 2 steam generator replacement project may 

not be necessary under this alternative; therefore, no temporary construction or grounddisturbing activities would occur onsite. Maintenance of transmission line ROWs would

continue. No additional impacts to terrestrial resources are expected as a result of shutdown of 

one of the two units.

The offsite wind power installation component of this alternative will require approximately 

64,000 ac (25,900 ha) of land, of which approximately 250 ac (101 ha) would be used. 

Construction disturbances associated with the wind power installation may significantly impact 

terrestrial ecology, and some erosion and sedimentation may result due to the location of wind 

power installations in mountainous, plains, or higher elevation areas where wind velocities are 

highest. However, because the wind power installations would be dispersed among a total area 

of approximately 64,000 ac (25,900 ha), and the potential exists to spread the installations 

among several locations, wildlife corridors resulting from construction and undisturbed buffer 

zones would continue to provide habitat for terrestrial species. No air pollutant deposition would 

result from this component of the alternative.

Impacts to terrestrial resources from this combination of alternatives at both the PINGP 1 and 2 

site and offsite locations are expected to be SMALL.

8.3.5 Human Health

EPA establishes NAAQS for six criteria pollutants (40 CFR Part 50) under the CAA. The CAA

recognizes two types of national air quality standards for particle pollution: primary standards 

set limits to protect public health, including the health of "sensitive" populations such as 

asthmatics, children, and the elderly; secondary standards set limits to protect public welfare, 

including protection against visibility impairment, damage to animals, crops, vegetation, and 

buildings.

The NRC established human health impacts for operating nuclear power reactors in 

10 CFR Part 51, Subpart A, Appendix B, Table B-1, which would apply to the continued 

operation of one PINGP 1 and 2 unit. 

No human health impacts would be caused by operation of wind power units. The increase in air 

emissions during the construction stage would be temporary in nature and could be minimized 

by use of appropriate air pollution reduction management practices. 

An energy efficiency program is unlikely to have a significant effect on human health. Changes 

to most building appliances would not affect health, though upgrades to HVAC systems, 

insulation, and weatherization (including windows) may affect indoor air quality. The GEIS noted 

that this issue has not been sufficiently studied, but that mitigation measures would be available 
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to correct problems. The GEIS also noted that hazardous chemicals in the waste stream would 

not affect human health. Accordingly, the NRC staff determined that these effects would be 

SMALL.

The implementation of the conservation portion of this alternative would have a minimal impact 

on the human health. Implementation of energy conservation measures such as sealing drafts 

and windows to be more air tight could cause an increase in radon, which can cause lung 

cancer. However, installation of more efficient ventilation systems, sealing cracks in basements, 

and other mitigative measures can reduce the concentration of radon in homes. The NRC staff 

concludes that the human health risks to members of the public from the conservation portion of 

this alternative would be SMALL.

The overall human health impacts from the combination 2 alternative would be SMALL.

8.3.6 Socioeconomics

The GEIS generically evaluates the impacts of nuclear power plant operations on land use both 

onsite and offsite of a power plant site. The analysis of land use impacts for this combination 

alternative focuses on the amount of land area that would be affected by the construction and 

operation of an offsite wind farm, which would be similar to the discussion on land use impacts 

in section 8.2.7 of this SEIS.

Land Use

The wind farm component of this combination alternative would produce 300 MWe of electricity 

and require approximately 64,000 ac (26,000 ha) spread over several locations. Turbine tower 

footings and infrastructure would only occupy roughly 5% of this area, while the remainder 

would be available for complementary land uses, like agriculture. The elimination of uranium 

fuel for one of the two PINGP 1 and 2 units could partially offset offsite land requirements. In the 

GEIS, the NRC staff estimated that approximately 1,000 ac (405 ha) would not be needed for 

mining and processing uranium during the operating life of a 1000-MWe nuclear power plant.

For operating only one unit at PINGP 1 and 2, roughly 552 ac (223 ha) of uranium mining area 

would no longer be needed. Overall land use impacts from this combination alternative would be 

SMALL to MODERATE, depending on local land use and the availability of land near the 

proposed sites.

Regarding the conservation portion of this alternative, quickly replacing and disposing of old 

inefficient appliances could generate waste material and potentially increase the size of landfills.

Roughly 4 to 5 years remain, respectively, before PINGP 1 and 2 licenses expire, thus some 

equipment may be replaced prior to the end of its expected life span in exchange for more 

efficient equipment, depending on how authorities ultimately structure a conservation program. 

Some programs may provide incentives for replacing less efficient equipment. In general, 

though, the cost of replacements and the average life of electrical equipment should allow for a 

somewhat gradual replacement process that favors replacement of older or shorter-lived 

equipment by more efficient equipment as it fails (especially in the case of frequently replaced 

items, like light bulbs). In addition, many items (like home appliances or industrial equipment) 

have substantial recycling value and would likely not be disposed of in landfills.

Impacts from continued operation of one PINGP 1 and 2 unit would remain a SMALL impact on 

land use as concluded in Chapter 4.9 of this SEIS. Overall impacts to land use from this 

combination alternative would be SMALL to LARGE depending on the location of the wind farm 

portion of this alternative. Some of these impacts could be reduced by locating the wind farms 

on previously disturbed areas, or locations that have existing land uses—like agriculture—that 
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can coexist with wind farms. Land use impacts can also be minimized by using existing 

transmission lines.

As previously discussed, socioeconomic impacts are defined in terms of changes to the 

demographic and economic characteristics and social conditions of a region. For example, the 

number of jobs created by the construction and operation of a wind farm could affect regional 

employment, income, and expenditures. Job creation is characterized in two ways: (1) 

construction-related jobs, which are transient, short in duration, and less likely to have a longterm socioeconomic impact; and (2) operation-related jobs in support of power plant operations, 

which have the greater potential for permanent, long-term socioeconomic impacts. Workforce 

requirements of power plant construction and operations for this combination alternative were 

determined in order to measure their possible effect on current socioeconomic conditions.

Socioeconomics

Plant shutdown of one of the two PINGP 1 and 2 units would have an impact on socioeconomic 

conditions in the region. Plant shutdown would eliminate approximately 342 jobs and would 

reduce tax revenue in the region. The loss of these contributions, which may not entirely cease 

until after decommissioning, could have a SMALL to MODERATE impact in reductions of tax 

revenues. Appendix J to NUREG-0586, Supplement 1 (NRC 2002) discusses of the potential 

socioeconomic impacts of plant decommissioning.

Estimated construction workforce requirements for this combination alternative would include 

300 workers for the wind power unit. The number of additional workers would cause a shortterm increase in the demand for services and temporary (rental) housing in the region around 

the construction sites.

After construction, and depending on the size of the community, some local communities may 

be temporarily affected by the loss of the construction jobs and associated loss in demand for 

business services. The rental housing market could also experience increased vacancies and 

decreased prices. The impact of construction on socioeconomic conditions would be SMALL.

Estimated operations workforce requirements for this combination alternative would include 50 

workers for the wind power unit. Given the small numbers of operations workers at these 

facilities, socioeconomic impacts associated with the operation of the wind farm would be 

SMALL.

Socioeconomic effects of the energy conservation efficiency program portion of this alternative 

would be SMALL. As noted in the GEIS, the program would likely employ additional workers.

Lower-income families could benefit from weatherization and insulation programs. This effect 

would be greater than the effect for the general population because low-income households 

experience home energy burdens more than four times larger than the average household 

(OMB 2007).

Overall, impacts to socioeconomics for this combination alternative would be SMALL, due to the 

relatively small numbers to additional workers required to run the one remaining nuclear reactor 

and wind portions of the alternative.

Traffic volumes on the roads in the vicinity of PINGP 1 and 2 would be reduced after one of the 

two units terminated operations. Most of the reduction in traffic volume would be associated with 

the loss of jobs at the plant. Deliveries to the plant would be reduced until decommissioning.

Transportation impacts associated with the shutdown of one reactor portion of this alternative 

would be SMALL.

Transportation
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Construction and operation of a wind farm would increase the number of vehicles on roads in 

the vicinity of the facility. During construction, cars and trucks would deliver workers, materials, 

and equipment to the worksite. The increase in vehicular traffic would peak during shift changes 

resulting in temporary levels of service impacts and delays at intersections. Transporting 

components of wind turbines could have a noticeable impact, but are likely to be spread over a 

large area. Any transportation effects from the energy conservation portion of this alternative 

would be widely distributed across the state, and would be SMALL to MODERATE. 

During plant operations, transportation impacts would almost disappear. Given the small 

numbers of operations workers at the wind farm, overall impacts on transportation associated 

with this combination alternative would be SMALL.

As previously discussed, aesthetic resources are the natural and manmade features that give a 

particular landscape its character and aesthetic quality. The aesthetics impact analysis focuses 

on the degree of contrast between the power generating plant and the surrounding landscape 

and the visibility of the power plant.

Aesthetics

Plant structures and other facilities would remain in place until decommissioning. Noise caused 

by plant operation would be reduced. Aesthetic impacts of reactor shutdown of one of the two 

units at PINGP 1 and 2 would be SMALL.

The wind farm would have a greater aesthetic effect than the other elements of this combination 

alternative. Compared to a single power plant unit on 46 to 190 ac (19 to 77 ha), 500 turbines 

300 ft (100 m) in height spread over 64,000 ac (26,000 ha) acres could have significant impacts 

and, in the absence of larger topographic features, would be the major focus of viewer attention

as the most readily-visible structures around. In some areas where aesthetics are an important 

value, this may be objectionable.

Impacts from the energy conservation efficiency programs portion of this alternative would be

SMALL. NSP would continue to use the existing transmission lines. Traffic to the plant would 

decrease, however, as would noise and emissions. Some noise impacts could occur in 

instances of energy efficiency upgrades to major building systems, though this impact would be 

intermittent and short-lived.

Most of the aesthetic impacts of this alternative would be a result of the wind farm. Overall the 

aesthetic impacts associated with this combination alternative would be categorized as 

MODERATE to LARGE if the wind farm is built at a site where aesthetics are an important 

element of the natural environment, and SMALL to MODERATE at other locations.

Historic property as defined in 36 CFR Part 800 is described above in Section 8.1.7.

Historic and Archaeological Resources

Chapter 2 of this SEIS discusses the affected environment in terms of cultural and archeological 

resources in the vicinity of the PINGP 1 and 2 site. Impacts to historic and archeological 

resources from operation of one unit at the PINGP 1 and 2 site could be MODERATE; however, 

these impacts could be mitigated if the utility commitments discussed in Chapter 4 of this SEIS 

are implemented for continued operation of one unit. Regarding the wind farm portion of this 

alternative, impacts to cultural and archeological resources could be significant; however, 

selecting a site where survey results indicate low sensitivity or where land has already been 

disturbed would minimize the overall impacts. Impacts to cultural and archeological resources 

from the conservation portion of this alternative would be minimal.

Overall, the impacts to historic and archeological resources would be SMALL to MODERATE 

due to the relatively small amount of land required for the use of one nuclear reactor portion of 
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this alternative, and if the provisions discussed in 8.1.7 are used for the location of the offsite 

wind farm.

Section 4.9.7 of this SEIS addresses the purpose and content of an environmental justice 

impact analysis. In this section, the NRC staff evaluates the potential for disproportionately high 

and adverse human health and environmental effects on minority and low-income populations 

that could result from the construction and operation of this combination alternative. 

Environmental Justice

Impacts associated with the reactor shutdown of one PINGP 1 and 2 unit portion of this 

alternative would disproportionately affect the Prairie Island Indian Community (PIIC), due to the 

proximity of the PIIC and the PINGP 1 and 2 site. Appendix J of NUREG-0586, Supplement 1 

(NRC 2002) provides additional discussion of these impacts.

Minority and low-income populations could be affected by the construction and operation of 

wind power units. Some of these effects have been identified in resource areas discussed in this 

section. For example, increased demand for rental housing during construction could 

disproportionately affect low-income populations.

Weatherization programs could target low-income residents as a cost-effective energy efficiency 

option since low-income populations tend to spend a larger proportion of their incomes paying 

utility bills. According to the Office of Management and Budget, low income populations 

experience energy burdens more than four times as large as those of average households 

(OMB 2007). Impacts to minority and low-income populations from energy conservation 

efficiency programs portion of this alternative would be SMALL, depending on program design 

and enrollment.

Overall impacts on minority and low-income populations from this combination alternative could 

range from SMALL to MODERATE. Because reactor shutdown of one PINGP 1 and 2 unit 

would only require a small number of workers after the initial shutdown and the reduced number 

of employees required for two reactors at the PINGP 1 and 2 site, disproportionate effects such 

as increased demand for rental housing, are likely to be SMALL. The offsite wind farm could 

have MODERATE environmental justice impacts; however these effects could be reduced if the 

plant was located near a metropolitan area or on a previously disturbed site.

The following information is provided by the Prairie Island Indian Community.

Implementing this alternative would disproportionately impact the PIIC, as one of 

the two reactors would continue to operate for an additional twenty years.

No other community is as close to the PINGP as the Prairie Island Indian 

Community. No other community is impacted, in as many ways, as the Prairie 

Island Indian Community. Furthermore, these impacts will have a cumulative 

environmental justice impact on our community.

No other minority community or federally recognized Indian tribe is impacted the 

way the Prairie Island Indian Community is.

Even though only one PINGP unit would be operating, spent fuel will still 

accumulate at the ISFSI. No other community (within a 50 mile radius) is so 

close to a nuclear power plant and a nuclear waste storage facility.

No other community would be subjected to chronic radiological releases from 

one unit of the PINGP and gamma radiation from the ISFSI. For many of our 

members, their exposure to low levels of radiation is for their entire lifetime. 
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One unit of the PINGP would continue to transmit electricity via the high-voltage 

power lines located immediately next to several of our homes. 

One unit of the PINGP would continue to release tritium, which leaches into 

ground water on the tribe’s land. 

Our youth are worrying about the effects of an accident on their community and 

their futures. Even if one unit were operating, there is still the possibility of an 

accident. 

An accident at one unit could still devastate our community. The consequences 

would be the same—our homeland would be gone, our culture would be 

decimated, our means of providing services to tribal members would be gone, 

and our tribal members’ primary income would be gone. No other community 

faces this undesirable prospect.

No other community (within the 50 mile radius) has the emergency planning 

concerns the tribe does (i.e., only one access road). Operating with one unit 

would not alleviate emergency preparedness concerns.

No other community participates in state or federal proceedings (using its own 

resources) to the extent that the Prairie Island Indian Community does. Even with 

one unit operating, the tribe would still need to participate in state and federal 

proceedings.

We believe that all things are related and that you cannot affect one thing without 

affecting another. Taken together, we believe that the operation of even one unit 

of the PINGP will have an integrated and cumulative negative impact on our 

community that will continue impact our community well after the twenty-year 

extended operating period.

8.3.7 Waste Management

The waste impacts associated with the continued operation of one PINGP 1 and 2 unit are 

outlined in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B. Wastes related to 

refurbishment and routine maintenance projects would be disposed in a permitted manner, 

either onsite or offsite at an authorized disposal facility.

The quantity of wastes generated during installation or implementation of conservation 

measures, which would depend on a number of factors, including appropriate disposal of old 

appliances, installation of control devises, and building modifications, would increase, but 

implementation of recycling programs could help minimize the amount of generated waste.

There would be minimal waste associated with the routine maintenance of the wind generating 

units.

The NRC staff concludes that waste impacts from this combination alternative would be SMALL.

8.4 Purchased Power

In the ER (NMC 2008), NSP indicated that purchased power would likely come from a variety of 

sources, most of which have already been considered in this section, though it could also 

include older, coal-fired power plants. Further, NSP indicated that relying on purchased power 

to replace PINGP 1 and 2 would likely result in construction of new facilities elsewhere in the 

region, given existing regional supply and demand, and would also require the construction of 

additional 500-kilovolt (kV) or 345-kV transmission lines. In other words, purchased power may 
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incur similar construction-related impacts to the alternatives already considered, while requiring 

additional impacts for new transmission projects. In the ER, NSP assumed that 100 mi (160 

km) of new transmission line in a new corridor 150 ft (46 m) wide may be necessary. The NRC 

staff notes that purchased power could serve as an alternative to license renewal, but the 

impacts would likely be larger than those for the alternatives already considered in this SEIS 

because substantial new transmission lines would likely be necessary. As a result, the NRC 

staff has not separately evaluated purchased power as an alternative to license renewal.

8.5 Alternatives Considered but Dismissed

In this section, we discuss the energy alternatives that we initially considered, but that we 

determined either would not individually meet the purpose and need identified in the GEIS or 

whose costs preclude consideration in greater depth. As you’ll note, we considered several of 

these alternatives in the combination alternatives in Sections 8.2 and 8.3.

8.5.1 Wind Power

The American Wind Energy Association indicates that Minnesota currently ranks 4th among the 

states in installed wind power capacity with 1752 MWe wind-powered electricity (AWEA 

Undated). Resource evaluations by Minnesota’s Department of Commerce indicate that wind 

project in most of western and southern Minnesota can operate at capacity factors from 36 to 

nearly 45 percent (MNDOC 2006a). Roughly one-third of the state has wind resources in power 

classes 4 through 7 (MNDOC 2006b). Generally, wind power classes 4 and above are 

considered adequate for wind power production. Further, Xcel Energy indicated in its 2007 

Minnesota Resource Plan (Xcel 2007xx) that it would need to add 2600 MW of wind capacity by 

2020 to comply with Minnesota’s Renewable Energy Standard (RES).

Despite Minnesota’s excellent wind power potential and Xcel’s potentially large capacity 

additions, wind power is not yet suitable for stand-alone large baseload capacity. When paired 

with energy storage or a readily dispatchable power source like hydropower, wind could serve 

as a means of providing baseload power. While Xcel Energy indicates that is about to begin 

testing of a large-scale battery backup for wind power (Xcel 2008), the potential for large-scale 

implementation of battery backup is not yet clear. In addition, hydropower resources in 

Minnesota (addressed in 8.4.5) are too small to provide backup for a wind power alternative. 

Further, Xcel Energy staff indicated at the NRC site audit that it is not currently possible to 

expand hydropower purchases from Manitoba Hydro. 

Given wind power’s intermittency and the lack of available backup, NRC staff will not consider 

wind power as a stand-alone alternative to license renewal. However, given Minnesota’s 

significant wind resource and Xcel’s large potential capacity additions, the NRC staff will 

consider wind power as a portion of a combination alternative.

8.5.2 Wood Waste

In 1999, DOE researchers estimated that Minnesota has biomass fuel resources consisting of 

urban, mill, agricultural, and forest residues, as well as speculative potential for energy crops. 

Excluding potential energy crops, DOE researchers projected that Minnesota had 15,464,325

tons (14,028,999 MT) of plant-based biomass available at $50 per ton delivered (Walsh et al. 

2000; costs are in 1995 dollars). The Bioenergy Feedstock Development Program at Oak Ridge 

National Laboratory estimated that each air-dry pound of wood residue produces approximately 

6400 Btu of heat (ORNL 2007). Assuming a 33 percent conversion efficiency, using all plantbased biomass available in Minnesota at $50 per ton (the maximum price the researchers 
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considered) would generate roughly 29 terawatt hours of electricity. This is roughly three and a 

half times the electricity PINGP 1 and 2 generated in 2006. However, most of this potential 

comes from agricultural residues. Excluding agricultural residues (many of which are 

traditionally left on fields following harvest and provide fertilization for the following years crops), 

the total potential is 6.6 terawatt-hours.

Walsh et al. (2000) go on to note that these estimates of biomass capacity contain substantial 

uncertainty and that potential availability does not mean biomass will actually be available at the 

prices indicated or that resources will be usably free of contamination. Some of these plant 

wastes already have reuse value and would likely be more costly to deliver because of 

competition. Others, such as forest residues, may prove unsafe and unsustainable to harvest on 

a regular basis.

As a result of limited resource availability, NRC staff will not consider wood waste as a standalong alternative to license renewal. NRC staff will, however, consider wood waste a portion of a 

combination alternative.

8.5.3 Energy Conservation

The Minnesota Next Generation Energy Act of 2007 set energy reduction goal of 1.5 percent of 

annual retail sales per year for each utility in the state (Chapter 136-S.F.No. 145). By the time 

the current license for PINGP 1 and 2, Unit 2, expires, the reduction goal would have all utilities 

in the state reduce sales by approximately 10 percent. In 2006, total retail sales of electricity 

were roughly 67 terawatt-hours of electricity (EIA 2007b), while PINGP 1 and 2 produced 

approximately 8.1 terawatt-hours of electricity in the same year (NMC 2008). PINGP 1 and 2’s 

generation accounted for roughly 12 percent of electricity sold in the state of Minnesota. The 

conservation goals of Minnesota statute, then, appear unable to replace the power generated by 

PINGP 1 and 2. 

The NRC staff had difficulty identifying further studies on conservation of energy efficiency 

potential in Minnesota. Given the size of the state’s goal and apparent lack of other estimates of 

conservation potential in the state, the NRC staff will not evaluate conservation as a stand-along 

alternative. The NRC staff will, however, consider it as a portion of a combination alternative, 

given its potential for low environmental impacts.

8.5.4 Solar Power

Solar technologies use the sun’s energy to produce electricity. Minnesota receives between 4 

and 5 kWh per square meter per day, or approximately 0.4 to 0.5 kWh of solar radiation per 

square foot per day, for solar collectors oriented at an angle equal to the installation’s latitude

(NREL 2009). At this level of incident solar radiation, photovoltaics are likely to be more

effective than solar thermal power plants. Because flat-plate photovoltaics tend to be roughly 25 

percent efficient, a solar-powered alternative would require 4390 to 5480 ac (1780 to 2220 ha)

of collectors to provide an amount of electricity equivalent to that generated by PINGP 1 and 2. 

Space between collectors and associated infrastructure increase this land requirement. This 

amount of land, while large, is consistent with the land required for coal and natural gas fuel 

cycles.

In the GEIS, the NRC staff noted that, by its nature, solar power is intermittent (i.e., it does not 

work at night and cannot serve baseload), and the efficiency of collectors varies greatly with 

weather conditions. A solar-powered alternative will require energy storage or a backup power 

supply to provide electric power at night. As noted in the wind energy section, 8.4.1, energy 
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storage technologies are in early stages of development and not yet large enough to backup 

enough capacity to replace PINGP 1 and 2.

Given the challenges in meeting baseload requirements, the NRC staff did not evaluate solar 

power as an alternative to license renewal of PINGP 1 and 2.

8.5.5 Hydroelectric Power

According to researchers at Idaho National Energy and Environmental Laboratory, Minnesota

has an estimated 225.9 MWe of technically available, undeveloped hydroelectric resources at 

40 project sites throughout the state (INEEL 1996). This amount occurs almost entirely in small 

installations, with only one site capable of generating more than 15 MWe.

The NRC staff notes that the total available hydroelectric potential is much smaller than the 

capacity of PINGP 1 and 2, and will not consider hydroelectric power as an alternative to license 

renewal.

8.5.6 Geothermal Power

Geothermal energy has an average capacity factor of 90 percent and can be used for baseload 

power where available. However, geothermal electric generation is limited by the geographical 

availability of geothermal resources (NRC 1996). As illustrated by Figure 8.4 in the GEIS, no 

feasible location for geothermal capacity exists to serve as an alternative to PINGP 1 and 2. The 

NRC staff concluded that geothermal energy is not a reasonable alternative to license renewal

of PINGP 1 and 2.

8.5.7 Biofuels

In addition to wood and municipal solid-waste fuels, there are other concepts for biomass-fired 

electric generators, including direct burning of energy crops (crops grown specifically as fuel or 

feedstock for fuel), conversion to liquid biofuels, and biomass gasification. In the GEIS, the NRC 

staff indicated that none of these technologies had progressed to the point of being competitive 

on a large scale or of being reliable enough to replace a baseload plant such as PINGP 1 and 2. 

After reevaluating current technologies, the NRC staff finds that other biomass-fired alternatives 

are still unable to reliably serve as an alternative to the continued operation of PINGP 1 and 2 

and does not consider biofuels to be a viable alternative to PINGP 1 and 2 license renewal.

8.5.8 New Nuclear Power

Sources in the nuclear industry have recently indicated that reactor projects currently under 

development are likely eight or nine years from completion, or possibly online in the 2016-2017 

timeframe (Nucleonics Week 2008). This is two to three years after the expiration of the license 

for PINGP 1 and 2, Unit 2, and three to four years after the expiration of the license for PINGP 1 

and 2, Unit 1. Further, potential plant owners or operators wishing to submit a new proposal 

specifically to offset the capacity of PINGP 1 and 2 would require additional time to develop an 

application. Given the relatively short time remaining on the current PINGP 1 and 2 operating 

licenses compared to the time to license and construct a new nuclear power plant, the NRC 

staff has not evaluated new nuclear generation as an alternative to license renewal.

8.5.9 Coal-fired Power

Minnesota’s Next Generation Energy Act explicitly caps utility-sector emissions of carbon 

dioxide and places a moratorium on constructing “new large energy facilities” as of August 1, 
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2009 (Chapter 136-S.F.No. 145). While the definition of “new large energy facility” excludes 

gas-fired and other turbine or combined-cycle plants, it includes coal-fired facilities. The law also 

prevents Minnesota utilities from purchasing power from new coal-fired power plants located 

outside of Minnesota. Given legal restrictions on the construction of new coal-fired power plants 

in the state and the purchase of power from outside the state, the NRC staff will not consider 

coal-fired power as an alternative to PINGP 1 and 2 license renewal.

8.5.10 Oil-fired Power

EIA’s 2008 Annual Energy Outlook, in contrast to past years’ projections, no longer indicates

that oil-fired power will account for any additions to capacity in the U.S. (EIA 2008a). The 

variable costs of oil-fired generation tend to be greater than those of the nuclear or coal-fired 

options, and oil-fired generation tends to have greater environmental impacts than natural gasfired generation. The high cost of oil (even prior to the record-high prices of 2008) has prompted 

a steady decline in its use for electricity generation. Thus the NRC staff did not consider oil-fired 

generation as an alternative to PINGP 1 and 2 license renewal.

8.5.11 Fuel Cells

Fuel cells oxidize fuels without combustion and related environmental side effects. Power is 

produced electrochemically by passing a hydrogen-rich fuel over an anode and air (or oxygen) 

over a cathode and separating the two by an electrolyte. The only byproducts (depending on 

fuel characteristics) are heat, water, and CO2. Hydrogen fuel can come from a variety of 

hydrocarbon resources by subjecting them to steam under pressure. Natural gas is typically 

used as the source of hydrogen.

At the present time, fuel cells are not economically or technologically competitive with other 

alternatives for baseload electricity generation. EIA projects that fuel cells may cost $5,374 per 

installed kW (total overnight costs), or 3.5 times the construction cost of new coal-fired capacity 

and 7.5 times the cost of new, advanced gas-fired, combined-cycle capacity (EIA 2008b). In 

addition, fuel cell units are likely to be small in size (the EIA reference plant is 10 MWe). While it 

may be possible to use a distributed array of fuel cells to provide an alternative to PINGP 1 and 

2, it would be extremely costly to do so. Accordingly, the NRC staff does not consider fuel cells 

as an alternative to PINGP 1 and 2 license renewal.

8.5.12 Municipal Solid Waste

Municipal solid waste combustors incinerate waste to produce steam, hot water, or electricity.

Combustors use three types of technologies—mass burn, modular, and refuse-derived fuel.

Mass burning is currently the method used most frequently in the U.S. and involves little to no

sorting, shredding, or separation. Consequently, toxic or hazardous components present in the 

waste stream are combusted, and toxic constituents are exhausted to the air or become part of 

the resulting solid wastes. Currently, approximately 89 waste-to-energy plants operate in the 

U.S. These plants generate approximately 2700 MWe, or an average of approximately 30 MWe 

per plant (IWSA 2007). Approximately 35 average-sized plants will be necessary to provide the 

same level of output as the other alternatives to PINGP 1 and 2 license renewal.

The GEIS indicates that the overall level of construction impact from a waste-fired plant will be 

similar to that for a coal-fired power plant. The GEIS also indicates that waste-fired plants have 

the same or greater operational impacts than coal-fired technologies (including impacts on the 

aquatic environment, air, and waste disposal). The initial capital costs for municipal solid-waste 

plants are greater than for comparable steam-turbine technology at coal-fired facilities or at 
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wood-waste facilities because of the need for specialized waste separation and handling 

equipment (NRC 1996).

Regulatory structures that once supported municipal solid waste incineration no longer exist. 

For example, the Tax Reform Act of 1986 made capital-intensive projects such as municipal 

waste combustion facilities more expensive relative to less capital-intensive waste disposal 

alternatives such as landfills. Also, the 1994 Supreme Court decision C&A Carbone, Inc. v. 

Town of Clarkstown, New York, struck down local flow control ordinances that required waste to 

be delivered to specific municipal waste combustion facilities rather than landfills that may have 

had lower fees. Additionally, environmental regulations have increased the capital cost 

necessary to construct and maintain municipal waste combustion facilities.

Given the small average installed size of municipal solid waste plants and the unfavorable 

regulatory environment, the NRC staff does not consider municipal solid waste combustion to 

be a feasible alternative to PINGP 1 and 2 license renewal.

8.5.13 Delayed Retirement

In the PINGP 1 and 2 ER, NSP indicated that any plans to upgrade older baseload plants are 

already included in its plans to meet future energy needs (NMC 2008). NSP did not indicate that 

it had plans to retire any of its currently-operating plants. As a result, the NRC staff will not 

consider delayed retirement as an alternative to PINGP 1 and 2 license renewal.

8.6 No-Action Alternative

This section will examine the environmental effects that occur if NRC takes no action. No action 

in this case means that NRC does not issue renewed operating licenses for PINGP 1 and 2 and 

the licenses simply expire at the end of the current license term, in 2013 and 2014, respectively. 

If NRC takes no action, the plant will shutdown at or before the end of the current license. After 

shutdown, plant operators will initiate decommissioning according to 10 CFR 50.82.

The NRC staff notes that no action is the only alternative considered in-depth that does not 

satisfy the purpose and need for this SEIS, as it does not provide power generation capacity. 

The no-action alternative would not meet the energy needs currently met by PINGP 1 and 2 or 

that the alternatives evaluated in sections 8.1 through 8.3 would satisfy. Assuming that a need 

currently exists for the power generated by PINGP 1 and 2, the no-action alternative would 

require the appropriate energy planning decision makers to rely on another alternative or 

conservation to replace or offset PINGP 1 and 2’s capacity.

In this section, the NRC staff addresses only those impacts that arise directly as a result of plant 

shutdown. The NRC staff has already addressed environmental impacts from decommissioning 

and related activities in several other documents. These documents include the Final Generic 

Environmental Impact Statement on Decommissioning of Nuclear Facilities, NUREG-0586, 

Supplement 1 (NRC 2002); the license renewal GEIS (Chapter 7; NRC 1996); and Chapter 7 of 

this SEIS. These analyses either directly address or bound the environmental impacts of 

decommissioning whenever NSP ceases operating PINGP 1 and 2.

The NRC staff notes that, even with a renewed operating license, PINGP 1 and 2 will eventually 

shut down, and the environmental effects addressed in this section will occur at that time. Since 

these effects have not otherwise been addressed in this SEIS, the NRC staff will address the 

impacts in this section. As with decommissioning effects, it is likely that shutdown effects will be 

similar whether they occur at the end of the current license or at the end of a renewed license.
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Table 8-4. Summary of Environmental Impacts of No Action Compared to Continued 

PINGP 1 and 2 Operation

No Action Continued PINGP 1 and 2

Operation

Air Quality SMALL SMALL

Ground water SMALL SMALL

Surface Water SMALL SMALL

Ecology SMALL SMALL

Human Health SMALL SMALL

Socioeconomics SMALL to MODERATE SMALL TO MODERATE

Waste Management SMALL SMALL

8.6.1 Air Quality

If PINGP 1 and 2 are shut down, there would be a reduction in emissions from activities related 

to plant operation such as use of diesel generators and employees vehicles. In Chapter 4, NRC 

staff determined that these emissions would have a SMALL impact on air quality during the 

renewal term. Therefore, if the plant shuts down and emissions decrease, the impact to air 

quality would remain SMALL.

8.6.2 Ground Water Use and Quality

If PINGP 1 and 2 are shut down, the use of ground water would diminish as plant personnel are 

removed from the site and operations cease. Some ground water consumption would continue 

as a result of the limited staff remaining onsite to maintain facilities prior to decommissioning.

Impacts to ground water use and quality would remain SMALL.

8.6.3 Surface Water Use and Quality

The rate of consumptive use of surface water would decrease as the plant is shut down and the 

reactor cooling system continues to remove decay heat. Wastewater discharges would also be 

reduced considerably. Shutdown would have SMALL impacts on surface water resources, 

which would continue to decrease over the decommissioning phase.

8.6.4 Aquatic and Terrestrial Resources

Plant shutdown will minimally affect terrestrial resources. In Chapter 4 of this SEIS, the NRC 

staff concluded that the impacts of continued operation on terrestrial resources will be SMALL. 

No additional land disturbances onsite or offsite would occur. Maintenance of transmission line 

ROWs would continue, regardless of plant operation. Shutdown would reduce the already 

SMALL impacts to terrestrial ecology. Accordingly, the NRC staff concludes that impacts to 

terrestrial resources as a result of plant shutdown would be SMALL.

Because plant shutdown would result in less water withdrawal and discharge, the no-action 

alternative would reduce the already SMALL impacts to aquatic ecology; therefore, impacts to 

aquatic resources as a result of plant shutdown would be SMALL.
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8.6.5 Human Health

Human health risks would decrease following plant shutdown. The plant, which is currently 

operating within regulatory limits, would emit less gaseous and liquid radioactive material to the 

environment. Also, after shutdown, the variety of potential accidents at the plant (radiological or 

industrial) would be reduced to a limited set associated with shutdown events and fuel handling 

and storage. In Chapter 4 of this SEIS, the NRC staff concluded that the impacts of continued 

plant operation on human health would be SMALL. In Chapter 5, the NRC staff concluded that 

the impacts of accidents during operation were SMALL. Therefore, as radioactive emissions to 

the environment decrease, and as the likelihood and variety of accidents decrease following 

shutdown, the NRC staff concludes that the impacts to human health following plant shutdown 

would be SMALL.

8.6.6 Socioeconomics

Plant shutdown would not affect onsite land use. Plant structures and other facilities would 

remain in place until decommissioning. Transmission lines connected to PINGP 1 and 2 would 

remain in service after the plant stops operating, and maintenance of these transmission lines 

would continue as before. Impacts on land use from plant shutdown would be SMALL.

Land Use

Plant shutdown would have an impact on socioeconomic conditions in the region around PINGP 

1 and 2. Plant shutdown would eliminate approximately 685 jobs and would reduce tax revenue 

in the region. The loss of these contributions, which may not entirely cease until after 

decommissioning, would have a SMALL to MODERATE impact. Appendix J to NUREG 0586, 

Supplement 1 (NRC 2002) provides additional discussion of the potential socioeconomic 

impacts of plant decommissioning.

Socioeconomics

Traffic volumes on the roads in the vicinity of PINGP 1 and 2 would be reduced after plant 

shutdown. Most of the reduction in traffic volume would be associated with the loss of jobs at 

the plant. Deliveries to the plant would be reduced until decommissioning, at which point they 

would cease. Transportation impacts would be SMALL as a result of plant shutdown.

Transportation impacts would increase if a new energy facility were constructed on the PINGP 1 

and 2 site, as described in the alternatives above. 

Transportation

Plant structures and other facilities would remain in place until decommissioning, but plumes 

from the plant’s cooling towers would disappear entirely. Noise caused by plant operation would 

cease. Aesthetic impacts of plant closure would be SMALL.

Aesthetics

Plant shutdown will likely have no noticeable immediate impacts on historic and archaeological 

resources. Decommissioning methods would be described in a post-shutdown decommissioning 

activities report, which is required to be submitted to NRC within two years following cessation 

of operations. NRC requirements ensure that the decommissioning activities would be subject to 

a Section 106 review in accordance with the National Historic Preservation Act (NHPA). 

Additionally, if NSP’s commitments outlined on 4.9.6 of this SEIS are implemented, impacts 

from decommissioning would be reduced. It is unlikely that plant staff will begin deconstruction 

or remediation before decommissioning. Because existing transmission lines will remain 

Historic and Archaeological Resources
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energized, transmission line ROW maintenance would continue. In Chapter 4 of this SEIS, the 

NRC concluded that the impacts of continued plant operation on historic and archaeological 

resources could be MODERATE. Given the high potential for resources in the area, the NRC 

concludes that the impacts on historic and archaeological resources from plant shutdown could 

also be MODERATE.

The Following information is provided by the Prairie Island Indian Community.

If this alternative is implemented, the PINGP 1 and 2 would shut down and 

decommissioning would commence. Given the number of recorded 

archaeological sites and the high potential to encounter unrecorded sites within 

the PINGP 1 and 2 boundaries, the tribe agrees with the NRC’s conclusion that 

impacts could be MODERATE. It is expected that the Prairie Island Indian 

Community would be involved in the archaeological reconnaissance work 

associated with decommissioning.

Plant shutdown could disproportionately affect the PIIC, but would not disproportionately affect 

other minority and low-income populations outside of the immediate vicinity of PINGP 1 and 2.

Impacts to all the other resource areas pertaining to environmental justice are SMALL to 

MODERATE regarding the no-action alternative. Minority and low-income populations are 

generally concentrated in the urban area of Minneapolis-St. Paul. Thus, overall impacts to 

environmental justice from plant shutdown would be SMALL to MODERATE. Appendix J of 

NUREG 0586, Supplement 1 (NRC 2002), provides additional discussion of these impacts.

Environmental Justice

The following information is provided by the Prairie Island Indian Community.

As stated above, plant shut down could disproportionately affect the Prairie 

Island Indian Community. The tribe, however, views the disproportionate 

impacts in a positive way: 

Health risks from chronic exposure to low levels of radiation from the PINGP 1 

and 2 would decrease.

Risk to the community from accidents would be reduced. 

Risks to the community from the operation of the PINGP 1 and 2 would 

decrease.

Tritium contamination from plant operations would cease, thereby reducing 

health risks.

NSP will not apply for a license amendment for an extended power uprate, 

thereby eliminating all environmental and health impacts associated with the 

uprate. 

The risk of cumulative and integrated health and safety impacts would be 

reduced.

Cumulative and integrated environmental impacts would decrease. 

Overall, the long-term Environmental Justice impacts to the Prairie Island Indian 

Community from the implementation of the No Action alternative would be 

LARGE and positive.

Traffic impacts associated with decommissioning the PINGP 1 and 2 would be 

MODERATE. The impacts, however, would be of a short-duration. 
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Even if the PINGP 1 and 2 were to shut down, spent fuel stored at the ISFSI 

would remain indefinitely stranded on Prairie Island. It is not clear whether there 

be any plant personnel who would monitor the ISFSI operation and respond to 

any emergencies. The 2003 Settlement agreement between the tribe and NSP, 

related to the dry cask storage, would still be in effect.

8.6.7 Waste Management

If the no-action alternative were implemented, the generation of high-level waste would cease

and generation of low-level and mixed waste would decrease. Impacts from implementation of 

the no-action alternative are expected to be SMALL.

8.7 Alternatives Summary

In this chapter, we considered the following alternatives to PINGP 1 and 2 license renewal:

• a gas-fired combined-cycle plant at the PINGP 1 and 2 site and an 

undetermined alternate site

• a combination including a gas-fired unit, wind power, conservation, and 

wood-waste biomass, and

• a combination including continued operation of one of the two PINGP 1 

and 2 unit, wind power, and conservation.

Finally, the NRC staff considered the effects of no action by the NRC and the effects it would 

have. Impacts for all alternatives are summarized in Table 8.5. The impacts of license renewal 

for PINGP 1 and 2 are similar to or smaller than the impacts of the alternatives considered in 

this chapter in all resource areas. 
Alternatives

8-40

Table 8-5. Summary of Environmental Impacts of Proposed Action and Alternatives

PINGP 1 and 2 

License Renewal

Gas-fired at PINGP 

1 and 2 Site

Gas-fired at 

Alternate Site

Combination 

Alternative 1

Combinat

Alternativ

Air Quality SMALL MODERATE MODERATE MODERATE SMALL 

Ground Water SMALL SMALL SMALL SMALL SMALL 

Surface Water SMALL SMALL SMALL SMALL to 

MODERATE

SMALL 

Ecology SMALL SMALL SMALL to 

MODERATE

SMALL to 

MODERATE

SMALL 

Human Health SMALL SMALL SMALL MODERATE SMALL 

Socioeconomics SMALL TO 

MODERATE

SMALL to 

MODERATE

SMALL to 

MODERATE

SMALL to 

LARGE

SMALL 

LARGE

Waste Management SMALL SMALL SMALL SMALL SMALL 
Alternatives

8-41

8.8 References

10 CFR 51. U.S. Code of Federal Regulations, Title 10 “Environmental Protection Regulations 

for Domestic Licensing and Related Regulatory Functions,” Part 51, “Energy.”

40 CFR 50. U.S. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 

“Domestic Licensing of Production and Utilization Facilties.”

40 CFR 51. U.S. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

“Requirements for Preparation, Adoption, and Submittal of Implementation Plans.”

40 CFR 60. U.S. Code of Federal Regulations, Title 40, Protection of Environment, Part 60, 

“Standards of Performance for New Stationary Sources.”

42 U.S.C. §7475. United States Code. Title 42, “The Public Health and Welfare”; Section 7475, 

“Preconstruction Requirements.”

136-S.F.No. 145. Laws of Minnesota for 2007. “Next Generation Energy Act of 2007.” Available 

URL: https://www.revisor.leg.state.mn.us/data/revisor/law/2007/0/2007-136.pdf (accessed 

January 6, 2009). 

AWEA (American Wind Energy Association). Undated. “Resources: Wind Energy Projects (As 

of 12/31/2008).” Available URL: http://www.awea.org/projects/ (accessed February 4, 2009). 

CAA (Clean Air Act. 42 U.S.C. 7401, et seq.). United States Code, Title 42, The Public Health 

and Welfare, Chapter 85, “Air Pollution Prevention and Control.”

EIA (Energy Information Administration). 2006. “Cost and Quality of Fuel for Electric Plants, 

2004 and 2005.” DOE/EIA 0191(2006). Washington, D.C. Available URL: 

http://www.eia.doe.gov/cneaf/electricity/cq/cqa2005.pdf (accessed March 16, 2007). ADAMS 

No. ML082880730.

EIA (U.S. Department of Energy, Energy Information Administration). 2007a. “Summary 

Statistics for the United States.” Table ES1 from Electric Power Annual with data for 2006. 

Accessed at: http://www.eia.doe.gov/cneaf/electricity/epa/epates.html (accessed June 11, 

2008). ADAMS No. ML082880730.

EIA (U.S. Department of Energy, Energy Information Administration). 2007b. State Energy 

Profiles 2006. DOE/EIA-0348(01)/2. Washington, D.C. Available URL: 

http://www.eia.doe.gov/cneaf/electricity/st_profiles/sep2006.pdf (accessed January 22, 2009). 

EIA (U.S. Department of Energy, Energy Information Administration). 2008a. Annual Energy 

Outlook 2008 With Projections to 2030. DOE/EIA 0383(2008). Washington, D.C. Available URL: 

http://tonto.eia.doe.gov/FTPROOT/forecasting/0383(2008).pdf (accessed January 6, 2009). 

ADAMS No. ML082880730.

EIA (Energy Information Administration. 2008b. Assumptions to the Annual Energy Outlook 

2008 With Projections to 2030. DOE/EIA 0554(2008). Washington, D.C. Available URL: 

http://tonto.eia.doe.gov/FTPROOT/forecasting/0554(2007).pdf (accessed July 22, 2008). 

ADAMS No. ML082880730.

EPA (U. S. Environmental Protection Agency). 2008. “Particulate Matter: Health Effects.” 

Available URL: http://www.epa.gov/air/particlepollution/health.html (accessed December 12, 

2008). ADAMS No. ML083470281.

GE (General Electric Company). 2007. “Gas Turbine and Combined Cycle Products.” May 

2007. Available URL: http://www.gepower.com/prod_serv/products/gas_turbines_cc/
Alternatives

8-42

en/downloads/gasturbine_cc_products.pdf (accessed January 6, 2009). ADAMS No. 

ML082880731.

INEEL (Idaho National Engineering and Environmental Laboratory). 1996. “U.S. Hydropower 

Resource Assessment for Minnesota.” DOE/ID-10430(MN). Idaho Falls, ID. Available URL: 

http://hydropower.inl.gov/resourceassessment/pdfs/states/mn.pdf (accessed January 22, 2009).

July.

IWSA (Integrated Waste Services Association). 2007. “Waste-to-Energy and the Production Tax 

Credit.” Washington, DC. Available URL: http://www.wte.org/docs/FactSheetPTC.pdf (accessed 

May 24, 2007). ADAMS No. ML083050223.

MNDOC (Minnesota Department of Commerce). 2006a. “Minnesota’s Wind Resource by 

Capacity Factor at 80 Meters.” Available URL: http://www.state.mn.us/mn/externalDocs/

Commerce/80_Meter_Capacity_Factor_013106115407_80MeterCF.pdf (accessed February 4, 

2009). January.

Minnesota Department of Commerce (MNDOC). 2006b. “Minnesota’s Wind Resource by Wind 

Speed at 80 Meters.” Available URL: http://www.state.mn.us/mn/externalDocs/Commerce/

80_Meter_Wind_Speed_013106115153_80MeterWindSpeed.pdf (accessed February 4, 2009). 

January.

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NRC (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, Washington, D.C. 

ADAMS Nos. ML040690705 and ML040690738.

NRC (U.S. Nuclear Regulatory Commission). 1999. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, Main Report, “Section 6.3 – Transportation, Table 9.1, 

Summary of findings on NEPA issues for license renewal of nuclear power plants, Final Report.” 

NUREG-1437, Volume 1, Addendum 1, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 2002. Generic Environmental Impact Statement 

on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the Decommissioning of 

Nuclear Power Reactors. NUREG-0586, Supplement 1, Volumes 1 and 2. Washington, DC.

NREL (National Renewable Energy Laboratory). 2009. “United States Atlas of Renewable 

Resources.” Interactive Map. Available URL: http://mapserve2.nrel.gov/website/Resource_Atlas/

viewer.htm (accessed February 4, 2009).

Nucleonics Week. 2008. U.S. New Reactors More Likely Online in 2016 and Beyond, NEI 

Official Says. Vol. 49, No. 15. April 10, 2008.

OMB (U.S. Office of Management and Budget). 2007. “Detailed Information on the Low Income 

Home Energy Assistance Program Assessment.” Available URL: 

http://www.whitehouse.gov/omb/expectmore/detail/10001059.2003.html (accessed July 10, 

2007). ADAMS No. ML082880730.

ORNL (Oak Ridge National Laboratory). 2007. “Bioenergy Conversion Factors.” Available URL: 

http://bioenergy.ornl.gov/papers/misc/energy_conv.html (accessed November 6, 2007). ADAMS 

No. ML083050223.

Walsh, M.E., R.L. Perlack, A. Turhollow, D. de la Torre Ugarte, D.A. Becker, R.L. Graham, S.A. 

Slinsky, and D.E. Ray. 2000. “Biomass Feedstock Availability in the United States: 1999 State 
Alternatives

8-43

Level Analysis.” Available URL: http://bioenergy.ornl.gov/resourcedata/index.html (accessed 

May 22, 2007). ADAMS No. ML083050223.

Xcel Energy (Xcel). 2007. 2007 Minnesota Resource Plan. Available URL: 

http://www.xcelenergy.com/Company/About_Energy_and_Rates/Resource%20and%20Renewa

ble%20Energy%20Plans/Pages/2007_Minnesota_Resource_Plan.aspx. Accessed 28 August 

2009.

Xcel Energy. 2008. “Wind-to-Battery Project.” Available URL: 

http://www.xcelenergy.com/SiteCollectionDocuments/docs/wind-to-battery.pdf (accessed 

February 4, 2009).

9-1

9.0 CONCLUSION

This supplemental environmental impact statement (SEIS) contains the preliminary 

environmental review of Northern State Power Co. (NSP) application for a renewed operating 

license for Prairie Island Nuclear Generating Plant, Units 1 and 2 (PINGP 1 and 2) as required 

by Part 51 of Title 10, of the Code of Federal Regulations (10 CFR Part 51), the NRC’s 

regulations that implement the National Environmental Policy Act of 1969 (NEPA). Chapter 9 

presents the conclusions and recommendations from the site-specific environmental review of 

PINGP 1 and 2 and summarizes site-specific environmental issues of license renewal that were 

identified during the review. The environmental impacts of license renewal are summarized in 

Section 9.1; a comparison of the environmental impacts of license renewal and energy 

alternatives is presented in Section 9.2; unavoidable impacts of license renewal and energy 

alternatives and resource commitments are discussed in Section 9.3; and conclusions and NRC 

staff recommendations are presented in Section 9.4.

9.1 Environmental Impacts of License Renewal

Our review of site-specific environmental issues in this supplemental EIS leads us to conclude 

that issuing a renewed license would have SMALL impacts for 20 of the 21 Category 2 issues 

applicable to license renewal and refurbishment at PINGP 1 and 2, and MODERATE for one 

Category 2 issue applicable to license renewal and refurbishment at PINGP 1 and 2, as well as 

environmental justice and chronic effects of electromagnetic fields.

Mitigation measures were considered for each Category 2 issue, as applicable. For ground 

water and surface water use issues, current measures to mitigate the environmental impacts of 

plant operation were found to be adequate. Potential mitigation measures for reducing impacts 

from thermophilic microbiological organisms resulting from PINGP 1 and 2 thermal discharge

include periodically monitoring for thermophilic microbiological organisms in the water and 

sediments near the discharge, and prohibiting recreational use near the discharge plume. For 

aquatic resources issues, current measures to mitigate the environmental impacts of plant 

operation were found to be adequate including using closed and helper cycle cooling, fine-mesh 

screens, and flow limitations. Additional mitigative measures that PINGP 1 and 2 could add 

include operating in closed cycle more often, using the fine-mesh screens for a longer period of 

time, reducing intake velocities, and operating under reduced intake flows.

Impacts to known historic and archaeological resources are potentially expected from the 

continued operation of PINGP 1 and 2 during the license renewal term; however, with the 

commitments proposed by NSP, these impacts could be mitigated. These commitments would 

serve to integrate cultural resource considerations with ongoing PINGP 1 and 2 activities. 

Additionally, training of NSP staff in the Section 106 process would ensure that informed 

decisions are made when considering the effects of future projects on historic and 

archaeological resources. As previously discussed, lands not previously surveyed should be 

investigated by a professional archaeologist prior to any ground disturbance. 

The NRC also considered cumulative impacts of past, present, and reasonably foreseeable 

future actions, regardless of what agency (Federal or non-Federal) or person undertakes them. 

The staff concluded that cumulative impacts of PINGP 1 and 2 license renewal and 

refurbishment would be SMALL to LARGE for potentially affected resources.
Conclusion

9-2

9.2 Comparison of Environmental Impacts of License Renewal and Alternatives

In the conclusion to Chapter 8, we determined that impacts from license renewal are generally 

less than the impacts of alternatives to license renewal, with the exception of energy 

conservation and energy efficiency. In comparing likely environmental impacts from a gas-fired 

combined-cycle plant at the PINGP 1 and 2 site and an undetermined alternate site, a 

combination including a gas-fired unit, wind power, conservation, and wood-waste biomass, and

a combination including continued operation of one of the two PINGP 1 and 2 unit, wind power, 

and conservation, and environmental impacts from license renewal, we found that the energy 

conservation and energy efficiency alternative would result in the lowest environmental impact. 

Based on our analysis, we found that the impacts of license renewal are reasonable in light of 

the impacts from alternatives to the license renewal of PINGP 1 and 2.

9.3 Resource Commitments

9.3.1 Unavoidable Adverse Environmental Impacts

Unavoidable adverse environmental impacts are impacts that would occur after implementation 

of all feasible mitigation measures. Implementing any of the energy alternatives considered in 

this supplemental EIS, including the proposed action, would result in some unavoidable adverse 

environmental impacts.

Minor unavoidable adverse impacts on air quality would occur due to emission and release of 

various chemical and radiological constituents from power plant operations. Nonradiological 

emissions resulting from power plant operations are expected to comply with U.S. 

Environmental Protection Agency (EPA) emissions standards, though the alternative of 

operating a fossil-fueled power plant in some areas may worsen existing attainment issues. 

Chemical and radiological emissions would not exceed the National Emission Standards for 

Hazardous Air Pollutants.

During nuclear power plant operations, workers and members of the public would face 

unavoidable exposure to radiation and hazardous and toxic chemicals. Workers would be 

exposed to radiation and chemicals associated with routine plant operations and the handling of 

nuclear fuel and waste material. Workers would have higher levels of exposure than members 

of the public, but doses would be administratively controlled and would not exceed any 

standards or administrative control limits. In comparison, the alternatives entailing the 

construction and operation of a non-nuclear power generating facility would also result in 

unavoidable exposure to hazardous and toxic chemicals to workers and the general public.

The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 

hazardous waste, and nonhazardous waste would also be unavoidable. In comparison, 

hazardous and nonhazardous wastes would also be generated at non-nuclear power generating 

facilities. Wastes generated during plant operations would be collected, stored, and shipped for 

suitable treatment, recycling, or disposal in accordance with applicable Federal and State 

regulations. Due to the costs of handling these materials, power plant operators would be 

expected to conduct all activities and optimize all operations in a way that generates the 

smallest amount of waste practical.
Conclusion

9-3

9.3.2 Relationship Between Local Short-Term Uses of the Environment and the 

Maintenance and Enhancement of Long-Term Productivity

The operation of power generating facilities would result in short-term uses of the environment 

as described in Chapters 4, 5, 6, 7, and 8. “Short term” is the period of time during which 

continued power generating activities would take place.

Power plant operations would necessitate short-term use of the environment and commitments 

of resources, and would also commit certain resources (e.g., land and energy) indefinitely or 

permanently. Certain short-term resource commitments would be substantially greater under 

most energy alternatives, including license renewal, than under the No Action Alternative due to 

the continued generation of electrical power as well as continued use of generating sites and 

associated infrastructure. During operations, all energy alternatives would entail similar 

relationships between local short-term uses of the environment and the maintenance and 

enhancement of long term productivity.

Air emissions from power plant operations would introduce small amounts of radiological and 

nonradiological constituents to the region around the plant site. Over time, these emissions 

would result in increased concentrations and exposure, but are not expected to impact air 

quality or radiation exposure to the extent that public health and long-term productivity of the 

environment would be impaired.

Continued employment, expenditures, and tax revenues generated during power plant 

operations would directly benefit local, regional, and State economies over the short term. Local 

governments investing project-generated tax revenues into infrastructure and other required 

services could enhance economic productivity over the long term.

The management and disposal of spent nuclear fuel, low-level radioactive waste, hazardous 

waste, and nonhazardous waste would require an increase in energy and would consume 

space at treatment, storage, or disposal facilities. Regardless of the location, the use of land to 

meet waste disposal needs would reduce the long-term productivity of the land.

Power plant facilities would be committed to electricity production over the short term. After 

decommissioning these facilities and restoring the area, the land could be available for other 

future productive uses.

9.3.3 Irreversible and Irretrievable Commitments of Resources

This section describes the irreversible and irretrievable commitments of resources that have 

been identified in this supplemental EIS. Irreversible resources refer to when primary or 

secondary impacts limit the future options for a resource. An irretrievable commitment refers to 

the use or consumption of resources that are neither renewable nor recoverable for future use. 

Irreversible and irretrievable commitment of resources for electrical power generation would 

include the commitment of land, water, energy, raw materials, and other natural and man-made 

resources required for power plant operations. In general, the commitment of capital, energy, 

labor, and material resources would also be irreversible.

The implementation of any of the energy alternatives considered in this supplemental EIS would 

entail the irreversible and irretrievable commitment of energy, water, chemicals, and, in some 

cases, fossil fuels. These resources would be committed during the license renewal term and 

over the entire life cycle of the power plant and would essentially be unrecoverable.

Energy expended would be in the form of fuel for equipment, vehicles, and power plant 

operations and electricity for equipment and facility operations. Electricity and fuels would be 

purchased from offsite commercial sources. Water would be obtained from existing water supply 
Conclusion

9-4

systems. These resources are readily available, and the amounts required are not expected to 

deplete available supplies or exceed available system capacities.

The irreversible and irretrievable commitment of material resources includes materials that 

cannot be recovered or recycled, materials that are rendered radioactive and cannot be 

decontaminated, and materials consumed or reduced to unrecoverable forms of waste. 

However, none of the resources used by these power generating facilities are in short supply, 

and, for the most part, are readily available.

Various materials and chemicals, including acids and caustics, would be required to support 

operations activities. These materials would be derived from commercial vendors, and their 

consumption is not expected to affect local, regional, or national supplies.

The treatment, storage, and disposal of spent nuclear fuel, low-level radioactive waste, 

hazardous waste, and nonhazardous waste would require the irretrievable commitment of 

energy and fuel and would result in the irreversible commitment of space in disposal facilities.

9.4 Recommendations

Based on (1) the analysis and findings in the GEIS, (2) information provided in the 

environmental report (ER) submitted by NSP, (3) consultation with Federal, State, and local 

agencies, (4) a review of pertinent documents and reports, and (5) consideration of public 

comments received during scoping, the preliminary recommendation of the NRC staff is that the 

Commission determine that the adverse environmental impacts of license renewal for PINGP 1 

and 2 are not so great that preserving the option of license renewal for energy planning decision 

makers would be unreasonable.
10-1

10.0 LIST OF PREPARERS

This supplemental EIS was prepared by members of the Office of Nuclear Reactor Regulation, 

with assistance from other NRC organizations and contract support from Pacific Northwest 

National Laboratory.

Table 10-1. List of Preparers. Pacific Northwest National Laboratory provided contract 

support for the severe accident mitigation alternatives (SAMA) analysis, presented in 

Chapter 5 and Appendix F and the Prairie Island Indian Community provided expertise 

in Land Use, Socioeconomics, Cultural Resources, and Environmental Justice, 

presented in Chapters 2, 3, 4, 5, and 8 .

Name Affiliation Function or Expertise

Nuclear Regulatory Commission

Briana Balsam Nuclear Reactor Regulation Terrestrial Ecology; Project 

Support

Dennis Beissel Nuclear Reactor Regulation Hydrology

Paula Cooper Nuclear Reactor Regulation Project Manager

Jennifer Davis Nuclear Reactor Regulation Historic and Archaeological 

Resources

Nathan Goodman

Elaine Keegan

Nuclear Reactor Regulation

Nuclear Reactor Regulation

Project Manager

Project Manager

Stephen Klementowicz Nuclear Reactor Regulation Radiation Protection; Human 

Health

Ekaterina Lenning Nuclear Reactor Regulation Air Quality; Radiation 

Protection; Human Health 

Dennis Logan Nuclear Reactor Regulation Ecology

Sarah Lopas Nuclear Reactor Regulation Project Support;

Nonradiological Waste; TMO; 

EMF

Robert Palla Nuclear Reactor Regulation Severe Accident Mitigation 

Alternatives

Jeffrey Rikhoff Nuclear Reactor Regulation Socioeconomics; Land Use; 

Environmental Justice

Andrew Stuyvenburg Nuclear Reactor Regulation Alternatives

Allison Travers Nuclear Reactor Regulation Hydrology

Elizabeth Wexler Nuclear Reactor Regulation Aquatic Ecology

Prairie Island Indian Community

SAMA Contractors(a)

Steve Short Pacific Northwest National Laboratory Severe Accidents Mitigation 

Alternatives

Bruce Schmitt Pacific Northwest National Laboratory Severe Accidents Mitigation 
Preparers

10-2

Name Affiliation Function or Expertise

Nuclear Regulatory Commission

Alternatives

Tye Blackburn Pacific Northwest National Laboratory Severe Accidents Mitigation 

Alternatives

(a) Pacific Northwest National Laboratory is operated by Battelle for the U.S. Department of Energy
 

APPENDIX A 

COMMENTS RECEIVED ON THE PRAIRIE ISLAND NUCLEAR 

GENERATING STATION, UNITS 1 AND 2, ENVIRONMENTAL REVIEW 

A-1

A. Comments Received on the Prairie Island Nuclear Generating 

Station, Units 1 and 2, Environmental Review

Introduction

On April 11, 2008, the Nuclear Regulatory Commission (NRC) received an application from 

Northern States Power Co. (NSP) [formerly Nuclear Management Company, LLC (NMC)] for 

renewal of the operating license of Prairie Island Nuclear Generating Plant, Units 1 and 2 

(PINGP 1 and 2). PINGP 1 and 2 are located in Red Wing, Minnesota, which is in Goodhue 

County on the west bank of the Mississippi River. As part of the application, NSP submitted an 

environmental report (ER) prepared in accordance with the requirements of 10 CFR Part 51.

10 CFR Part 51 contains the NRC requirements for implementing the National Environmental 

Policy Act (NEPA) of 1969 and the implementing regulations promulgated by the Council on 

Environmental Quality (CEQ). Section 51.53 outlines requirements for preparation and submittal 

of environmental reports to the NRC.

Section 51.53(c)(3) was based upon the findings documented in NUREG-1437, “Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants,” (GEIS). The 

GEIS, which identified and evaluated the environmental impacts associated with license 

renewal, was first issued as a for public comment. The staff received input from Federal and 

State agencies, public organizations, and private citizens before developing the final document.

As a result of the assessments in the GEIS, a number of impacts were determined to be small 

and to be generic to all nuclear power plants. These were designated as Category 1 impacts.

An applicant for license renewal may adopt the conclusions contained in the GEIS for Category 

1 impacts, absent new and significant information that may cause the conclusions to fall outside 

those of the GEIS. Category 2 impacts are those impacts that have been determined to be 

plant-specific and are required to be evaluated in the applicant’s ER.

The Commission determined that the NRC does not have a role in energy planning decisionmaking for existing plants, which should be left to State regulators and utility officials. Therefore, 

an applicant for license renewal need not provide an analysis of the need for power, or the 

economic costs and economic benefits of the proposed action. Additionally, the Commission 

determined that the ER need not discuss any aspect of storage of spent fuel for the facility that 

is within the scope of the generic determination in 10 CFR 51.23(a) and in accordance with 

10 CFR 51.23(b). This determination was based on the Nuclear Waste Policy Act of 1982 and 

the Commission’s Waste Confidence Rule, 10 CFR 51.23.

On July 22, 2008, the NRC published a Notice of Intent in the Federal Register (73 FR 42628), 

to notify the public of the staff’s intent to prepare a plant-specific supplement to the GEIS (SEIS) 

regarding the renewal application for the PINGP 1 and 2 operating license. The plant-specific 

supplement to the GEIS will be prepared in accordance with NEPA, CEQ guidelines, and 

10 CFR Part 51. As outlined by NEPA, the NRC initiated the scoping process with the issuance 

of the Federal Register Notice. The NRC invited the applicant, federal, state, local, and tribal

government agencies, local organizations, and individuals to participate in the scoping process 

by providing oral comments at scheduled public meetings, which were held at the Red Wing 

Public Library, in Red Wing, Minnesota on July 30, 2008, and/or submitting written suggestions 

and comments no later than September 22, 2008. The NRC issued press releases, placed ads 

in the local paper, and distributed flyers locally to advertise the public meetings. Approximately 

75 people attended the meetings. Both sessions began with NRC staff members providing a 

brief overview of the license renewal process and the NEPA process. Following the NRC’s 

prepared statements, the meetings were open for public comments. Several attendees 
Appendix A

A-2

submitted written comments, others provided oral comments, which were transcribed by a 

certified court reporter. The transcripts of the meetings were issued on September 3, 2008 for 

the afternoon session and September 5, 2008 for the evening session. The transcripts are

available for public inspection in the NRC Public Document Room (PDR), located at One White 

Flint North, 11555 Rockville Pike, Rockville, Maryland, 20852, or from the NRC’s Agencywide 

Documents Access and Management System (ADAMS). The ADAMS Public Electronic Reading 

Room is accessible at http://www.nrc.gov/reading-rm/adams/web-based.html. The transcripts 

for the public meeting can be found in ADAMS at accession numbers ML082470336 and 

ML082490514. Persons who do not have access to ADAMS, or who encounter problems in 

accessing the documents located in ADAMS, should contact the NRC’s Public Document Room 

Reference staff by telephone at 1-800-397-4209, or 301-415- 4737, or by e-mail at 

pdr.resource@nrc.gov

The scoping process provides an opportunity for public participation to identify issues to be 

addressed in the SEIS and highlight public concerns and issues. The Federal Register Notice of 

Intent identified the following objectives of the scoping process:

.

• Define the proposed action

• Determine the scope of the SEIS and identify significant issues to be analyzed in 

depth

• Identify and eliminate peripheral issues

• Identify any environmental assessments and other environmental impact 

statements being prepared that are related to the SEIS

• Identify other environmental review and consultation requirements

• Indicate the schedule for preparation of the SEIS

• Identify any cooperating agencies 

• Describe how the SEIS will be prepared.

Scoping Comment Period Summary

During the scoping period, the NRC staff received six letters and three e-mails containing 

comments related to the environmental review for the proposed license renewal of PINGP 1 and 

2. Additionally, thirteen people provided oral comments or comments in writing during the July 

30, 2008, scoping meetings.

Individuals and/or groups and their affiliation (if applicable) that provided comments during the 

scoping period are identified in Table 1. A numerical commenter identification code (1-18) was 

assigned to each commenter for purposes of categorizing the comments.
Appendix A

A-3

Table 1. Individuals and/or Groups Providing Comments during Scoping Period. 

Commenters appear in alphabetical order, and each commenter has been 

given a unique commenter identification number.

Commenter Affiliation (if stated)

Commenter 

ID Number

Arneson, Scott Goodhue County Administrator 1

Betcher, Steve Goodhue County Attorney 2

Crocker, George Executive Director, North American Water Office 3

CURE Communities United for Responsible Energy 4

Eide-Tollefson, Kristen Resident, Florence Township MN 5

Foushee, Lea Environmental Justice Director, North American Water Office 6

Himanga, Katie Mayor, Lake City, Minnesota 7

Jackson, Mary Senior Planner, Dakota County Office Of Planning and 

Analysis 8

Johnson, Ron President, Prairie Island Tribal Council & Indian Community 9

Lemon, Gina Leech Lake Band of Ojibwe 10

Lovejoy, Tom Environmental Impact Coordinator, Wisconsin Department of 

Natural Resources 11

Marshman, Joan Chair, Florence Township Board of Supervisors 12

Muller, Alan Executive Director, Green Delaware 13

Overland, Carol none provided 14

PIIC Tribal Council Prairie Island Indian Community (PIIC) 15

Schultz, Michael Red Wing City Council 16

Vukmir, Andrija none provided 17

Wadley, Mike PINGP Site Vice President, Nuclear Management Company 

(NMC) 18

In order to evaluate the comments, the NRC staff gave each comment a unique identification 

code that categorizes the comment by technical issue and also allows each comment or set of 

comments to be traced back to the commenter and original source (transcript, letter, or e-mail) 

from which the comments were submitted.

Comments were placed into one of twenty-eight technical issue categories, which are based on 

the topics that will be contained within the staff’s supplemental environmental impact statement 

(SEIS) for PINGP 1 and 2, as outlined by the GEIS. These technical issue categories and their 

abbreviation codes are presented in Table 2. 
Appendix A

A-4

Table 2. Technical Issue Categories. Comments were divided into one of the 28 

categories below, each of which has a unique abbreviation code.

Abbreviation 

Code Technical Issue

Abbreviation 

Code Technical Issue

AM(a) Aging Management NW(a) Non-radiological Waste

AS Alternative Energy Sources ON(a) Opposition to Nuclear Power

AR Aquatic Resources OR(a) Opposition to License Renewal

CI Cumulative Impacts OS Outside of Scope(c)

CR Cultural Resources PA Postulated Accidents

EJ Environmental Justice RW Radioactive Waste

ER Environmental Report(b) SD Shutdown and 

Decommissioning

GW Groundwater SE Socioeconomics

HH Human Health SN Support of Nuclear Power

HP NRC Hearing Process SR Support for License Renewal

LR License Renewal and its 

Process SW Surface Water

LU(a) Land Use TE

Threatened and Endangered 

Species and Essential Fish 

Habitat

NO(a) Noise TR Terrestrial Resources

NS Nuclear Safety UR Uranium Fuel Cycle

(a)

No comments specific to the categories of aging management, land use, noise, non-radiological 

waste, opposition to nuclear power, or opposition to license renewal were submitted during the 

PINGP 1 and 2 scoping period.

(b) Comments contained in this category pertain to general quality or content of the applicant’s 

Environmental Report

(c)

Outside of Scope are those comments that pertain to issues that are not evaluated during the 

environmental review of license renewal and include, but are not limited to, issues such as need for 

power; emergency preparedness; security; terrorism; and spent nuclear fuel storage and disposal.

Presentation of Comments and Responses

This document contains a copy of each commenters’ submission(s) during the scoping period. 

For those that provided oral comments at the scoping meetings, comments are taken from the 

meeting transcripts. Each comment is bracketed and labeled with a unique comment 

identification number. Note that only those transcript pages on which each individual’s 

comments are contained are included in this document; however, the complete meeting 

transcripts can be accessed online or in-person from ADAMS at accession numbers 

ML082470336 and ML082490514. Please refer to the description of ADAMS above for an 

explanation of how to access these documents.

Comments Received During the Scoping Period
Appendix A

A-5

The NRC staff’s responses to each comment received during the scoping period are organized 

by technical issue. Each response is prefaced by a summary of the issue to which the 

comment(s) pertain and a list of the unique identification codes of the comments to which the 

response applies. Similar comments within a technical issue area may be considered together 

in the provided response. Some comments applied to more than one technical issue category 

(indicated by a “ / ” in the comment identification code), and are, therefore, addressed in more 

than one section of the staff’s responses. For example, the 3-c-ER/HH pertains to both the 

Environmental Report and Human Health and is, thus, addressed under both Environmental 

Report and Human Health in the staff’s responses.

Responses to Comments Received During the Scoping Period

Table 3 provides a complete list of comments received during the scoping period, along with the 

commenter, comment source (transcript, letter, or e-mail), page number(s) on which the 

comment and correlating response(s) appears in this document, and ADAMS accession number 

for the original source of the comment.

The preparation of the SEIS will take into account all the relevant issues raised during the 

scoping process. The SEIS will address both Category 1 and 2 issues, along with any new 

information identified as a result of scoping. The SEIS will rely on conclusions supported by 

information in the GEIS for Category 1 issues, and will include the analysis of Category 2 issues 

and any new and significant information. The SEIS will be made available for public comment.

The comment period will offer the next opportunity for the applicant, interested Federal, State, 

local, and tribal government agencies, local organizations, and members of the public to provide 

input to the NRC’s environmental review process. The comments received on the SEIS will be 

considered in the preparation of the final SEIS. The final SEIS, along with the staff’s Safety 

Evaluation Report (SER), will be considered by the NRC in reaching a decision on the PINGP 1 

and 2 license renewal application.
Appendix A

A-6

Table 3. Comments Received during Scoping Period. Comments are listed 

alphabetically by commenter, and each comment has a unique comment 

identification code.

Comment ID Commenter Comment 

Source

Comment 

Page 

No(s).

Response Page 

No(s).

ADAMS

Accession 

Number

1-a-SR Arneson, S. transcript(a) 13 163 ML082470336

2-a-SR Betcher, S. transcript 15-16 163 ML082470336

3-a-LR Crocker, G. transcript 18 157 ML082490514

3-b-HH Crocker, G. transcript 19-20 154 ML082490514

3-c-ER/HH Crocker, G. transcript 20-22 153, 154, 156 ML082490514

4-a-AS CURE letter 25 148, 149 ML083220369

4-b-AR/SW CURE letter 26-27 149, 163 ML083220365

4-c-SE CURE letter 27 163 ML083220365

4-d-AR/HH CURE letter 27 150, 154 ML083220365

4-e-HH CURE letter 27 154, 156 ML083220365

4-f-SW CURE letter 27-28 163 ML083220365

5-a-ER Eide-Tollefson, K. letter 31 153 ML083220377

5-b-GW/SW Eide-Tollefson, K. letter 31 153, 164 ML083220377

5-c-LR Eide-Tollefson, K. letter 31-32 158 ML083220377

5-d-SE Eide-Tollefson, K. letter 32 163 ML083220377

5-e-AR Eide-Tollefson, K. letter 32 150 ML083220377

5-f-EJ/RW Eide-Tollefson, K. letter 32 152, 161 ML083220377

5-g-CI/LR Eide-Tollefson, K. letter 33 151, 157 ML083220377

5-h-CI Eide-Tollefson, K. letter 33-34 151 ML083220377

5-i-OS Eide-Tollefson, K. letter 34 159 ML083220377

5-j-RW Eide-Tollefson, K. letter 34-35 161 ML083220377

5-k-OS/RW Eide-Tollefson, K. letter 35 159, 161 ML083220377

5-l-OS Eide-Tollefson, K. letter 35 159 ML083220377

5-m-CI/RW Eide-Tollefson, K. letter 35 151, 161 ML083220377

5-n-RW Eide-Tollefson, K. letter 35 161 ML083220377

5-o-CI/RW Eide-Tollefson, K. letter 35 151, 161 ML083220377

5-p-RW Eide-Tollefson, K. letter 36 161 ML083220377

5-q-CI/LR Eide-Tollefson, K. letter 36 151, 158 ML083220377

5-r-CI/LR Eide-Tollefson, K. letter 36-38 151, 152, 158 ML083220377

5-s-AS Eide-Tollefson, K. letter 38 148 ML083220377

5-t-AS Eide-Tollefson, K. letter 38 148 ML083220377
Appendix A

A-7

Comment ID Commenter Comment 

Source

Comment 

Page 

No(s).

Response Page 

No(s).

ADAMS

Accession 

Number

5-u-LR/OS Eide-Tollefson, K. letter 38-39 158 ML083220377

5-v-LR Eide-Tollefson, K. letter 39 158 ML083220377

5-w-CI Eide-Tollefson, K. letter 39-42 151 ML083220377

5-x-CI Eide-Tollefson, K. transcript 44 151 ML082490514

5-y-OS/RW Eide-Tollefson, K. transcript 44-45 159, 161 ML082490514

5-z-NS Eide-Tollefson, K. transcript 45 159 ML082490514

5-aa-RW Eide-Tollefson, K. transcript 45-47 161 ML082490514

6-a-HH Foushee, L. e-mail 49 154 ML083220386

6-b-EJ/UR Foushee, L. e-mail 49 152, 165 ML083220386

6-c-HH Foushee, L. e-mail 49-50 154 ML083220386

6-d-HH Foushee, L. e-mail 51-52 154 ML083220372

6-e-HH Foushee, L. e-mail 52 154 ML083220372

6-f-EJ/RW/UR Foushee, L. e-mail 52-53 152, 161, 165 ML083220372

6-g-LR Foushee, L. transcript 55-56 157 ML082490514

6-h-HH/LR Foushee, L. transcript 57-61 154, 158 ML082490514

6-i-ER/HH Foushee, L. transcript 62-63 153, 154 ML082490514

7-a-AR/RW/SW Himanga, K. letter 65 149, 161, 163 ML082660657

7-b-AR/CR/SW Himanga, K. letter 65-66 149, 151, 163 ML082660657

7-c-RW Himanga, K. transcript 68-69 161 ML082470336

7-d-AR/CR/SW Himanga, K. transcript 69 149, 151, 163 ML082470336

8-a-AR/PA/SW Jackson, M. e-mail 71-72 150, 160, 164 ML083220385

9-a-LR Johnson, R. transcript 74-75 157 ML082470336

10-a-CR Lemon, G. letter 77 151 ML082660601

11-a-AR Lovejoy, T. letter 79 149 ML083080277

11-b-NS Lovejoy, T. letter 79 159 ML083080277

11-c-AR/SW Lovejoy, T. letter 79 149, 163 ML083080277

11-d-EJ/SW Lovejoy, T. letter 80 152, 163 ML083080277

11-e-AR Lovejoy, T. letter 80 149 ML083080277

11-f-CI Lovejoy, T. letter 80 151 ML083080277

12-a-RW Marshman, J. transcript 82-83 161 ML082490514

13-a-HH Muller, A. transcript 85 154 ML082490514

13-b-LR Muller, A. transcript 86-87 158 ML082490514

13-c-ER/LR Muller, A. transcript 88-89 153, 158 ML082490514

13-d-LR Muller, A. transcript 89-90 158 ML082490514
Appendix A

A-8

Comment ID Commenter Comment 

Source

Comment 

Page 

No(s).

Response Page 

No(s).

ADAMS

Accession 

Number

13-e-SD Muller, A. transcript 90 162 ML082490514

13-f-OS Muller, A. transcript 90-92 159 ML082490514

13-g-UR Muller, A. transcript 93 165 ML082490514

13-h-RW Muller, A. transcript 93-94 161 ML082490514

13-i-AS Muller, A. transcript 94-95 148 ML082490514

13-j-HH Muller, A. transcript 95 154 ML082490514

14-a-LR Overland, C. transcript 97-98 158 ML082490514

14-b-AS Overland, C. transcript 98-99 148 ML082490514

14-c-LR Overland, C. transcript 99 157 ML082490514

15-a-ER PIIC Tribal Council letter 103-104 153 ML083200029

15-b-LR PIIC Tribal Council letter 104-105 157 ML083200029

15-c-LR PIIC Tribal Council letter 105 157 ML083200029

15-d-HH/EJ PIIC Tribal Council letter 105 152, 154, 156 ML083200029

15-e-GW PIIC Tribal Council letter 105-108 153 ML083200029

15-f-HH/EJ PIIC Tribal Council letter 108 152, 154 ML083200029

15-g-ER PIIC Tribal Council letter 108 153 ML083200029

15-h-HH PIIC Tribal Council letter 108-110 154, 156 ML083200029

15-i-RW PIIC Tribal Council letter 110-112 161 ML083200029

15-j-RW PIIC Tribal Council letter 112 161 ML083200029

15-k-AS PIIC Tribal Council letter 112 148 ML083200029

15-l-TR PIIC Tribal Council letter 112-114 164 ML083200029

15-m-CR PIIC Tribal Council letter 114-117 151 ML083200029

15-n-TE PIIC Tribal Council letter 117-119 165 ML083200029

15-o-SE PIIC Tribal Council letter 119-120 163 ML083200029

15-p-OS PIIC Tribal Council letter 120 159 ML083200029

15-q-SE PIIC Tribal Council letter 120 163 ML083200029

15-r-EJ PIIC Tribal Council letter 120-121 152 ML083200029

15-s-EJ PIIC Tribal Council letter 121 152 ML083200029

15-t-HH PIIC Tribal Council letter 121 157 ML083200029

15-u-PA PIIC Tribal Council letter 122 160 ML083200029

15-v-CI/OS/RW PIIC Tribal Council letter 123 151, 159, 161 ML083200029

15-w-OS/RW PIIC Tribal Council letter 123 159, 161 ML083200029

15-x-ER PIIC Tribal Council letter 123 153 ML083200029

15-y-ER/LR PIIC Tribal Council letter 123-124 153, 158 ML083200029
Appendix A

A-9

Comment ID Commenter Comment 

Source

Comment 

Page 

No(s).

Response Page 

No(s).

ADAMS

Accession 

Number

15-z-CI/ER PIIC Tribal Council letter 125 151, 153 ML083200029

15-aa-EJ PIIC Tribal Council letter 125 152 ML083200029

15-bb-EJ PIIC Tribal Council letter 125-126 152 ML083200029

15-cc-AS PIIC Tribal Council letter 126 148 ML083200029

15-dd-SW PIIC Tribal Council letter 126 164 ML083200029

15-ee-OS/SW PIIC Tribal Council letter 126 159, 164 ML083200029

15-ff-OS PIIC Tribal Council letter 127 159 ML083200029

15-gg-HH PIIC Tribal Council letter 127 155 ML083200029

15-hh-OS PIIC Tribal Council letter 127 160 ML083200029

16-a-SR Schultz, M. transcript 132-134 163 ML082470336

17-a-SN Vukmir, A. transcript 136 163 ML082470336

17-b-SR Vukmir, A. transcript 136 163 ML082470336

17-c-SN Vukmir, A. transcript 136-137 163 ML082470336

17-d-RW Vukmir, A. transcript 138 161 ML082470336

17-e-SR Vukmir, A. transcript 138 163 ML082470336

18-a-SR Wadley, M. transcript 140-142 163 ML082470336

18-b-NS Wadley, M. transcript 142-144 159 ML082470336

18-c-NS Wadley, M. transcript 145 159 ML082470336

18-d-SR Wadley, M. transcript 145-146 163 ML082470336

18-e-SR Wadley, M. transcript 146 163 ML082470336

18-f-SR Wadley, M. transcript 146-147 163 ML082470336

(a) Comments were received orally during one of two scoping meetings held on July 30, 2009, and 

transcribed by a certified court reporter.
Appendix A

A-10

The following pages contain the original comment letters, e-mail messages, 

and public meeting transcripts pertaining to the PINGP 1 and 2 scoping 

summary report. Each commented is labeled and identified by a unique 

comment identification code.
Appendix A

A-11

The following pages contain the comments

made by Scott Arneson during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-12

1-a-SR
Appendix A

A-13

The following pages contain the comments

made by Steve Betcher during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-14

2-a-SR
Appendix A

A-15

2-a-SR

(continued)
Appendix A

A-16

The following pages contain the comments

made by George Crocker during 

the NRC public scoping meetings held on July 30, 2008 
Appendix A

A-17

3-a-LR
Appendix A

A-18

3-b-HH
Appendix A

A-19

3-b-HH 

(continued)

3-c-ER/HH
Appendix A

A-20

3-c-ER/HH 

(continued)
Appendix A

A-21

3-c-ER/HH 

(continued)
Appendix A

A-22

The following pages contain the written comments

submitted by the Communities for

Responsible Energy during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-23

4-a-AS
Appendix A

A-24

4-a-AS

(continued)
Appendix A

A-25

4-b-AR/SW
Appendix A

A-26

4-e-HH

4-f-SW

4-d-AR/HH

4-c-SE

4-b-AR/SW 

(continued)
Appendix A

A-27

4-f-SW 

(continued)
Appendix A

A-28

The following pages contain the written comments

submitted by Kristen Eide-Tollefson during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-29
Appendix A

A-30

5-a-ER

5-c-LR

5-b-GW/SW
Appendix A

A-31

5-c-LR

(continued)

5-d-SE

5-e-AR

5-f-EJ/RW
Appendix A

A-32

5-g-CI/LR

5-h-CI
Appendix A

A-33

5-i-OS

5-h-CI 

(continued)

5-j-RW
Appendix A

A-34

5-j-RW 

(continued)

5-m-CI/RW

5-n-RW

5-o-CI/RW

5-k-OS/RW

5-l-OS
Appendix A

A-35

5-p-RW

5-q-CI/LR

5-r-CI/LR
Appendix A

A-36

5-r-CI/LR

(continued)
Appendix A

A-37

5-r-CI/LR

(continued)

5-t-AS

5-u-LR/OS

5-s-AS
Appendix A

A-38

5-u-LR/OS 

(continued)

5-w-CI

5-v-LR
Appendix A

A-39

5-w-CI 

(continued)
Appendix A

A-40

5-w-CI

(continued)
Appendix A

A-41

5-w-CI 

(continued)
Appendix A

A-42

The following pages contain the comments

made by Kristen Eide-Tollefson during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-43

5-x-CI

5-y-OS/RW
Appendix A

A-44

5-y-OS/RW

(continued)

5-z-NS

5-aa-RW
Appendix A

A-45

5-aa-RW 

(continued)
Appendix A

A-46

5-aa-RW

(continued)
Appendix A

A-47

The following pages contain the written comments

submitted by Lea Foushee during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-48

6-a-HH

6-b-EJ/UR

6-c-HH
Appendix A

A-49

6-c-HH

(continued)
Appendix A

A-50

6-d-HH
Appendix A

A-51

6-d-HH

(continued)

6-e-HH

6-f-EJ/RW/UR
Appendix A

A-52

6-f-EJ/RW/UR 

(continued)
Appendix A

A-53

The following pages contain the comments

made by Lea Foushee during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-54

6-g-LR

(continued)

6-g-LR
Appendix A

A-55

6-g-LR 

(continued)
Appendix A

A-56

6-h-HH/LR
Appendix A

A-57

6-h-HH/LR 

(continued)
Appendix A

A-58

6-h-HH/LR

(continued)
Appendix A

A-59

6-h-HH/LR 

(continued)
Appendix A

A-60

6-h-HH/LR

(continued)
Appendix A

A-61

6-i-ER/HH
Appendix A

A-62

6-i-ER/HH 

(continued)

6-i-ER/HH 

(continued)

6-i-ER/HH 

(continued)
Appendix A

A-63

The following pages contain the written comments

submitted by Katie Himanga during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-64

7-b-AR/CR/SW

7-a-AR/RW/SW
Appendix A

A-65

7-b-AR/CR/SW

(continued)
Appendix A

A-66

The following pages contain the comments

made by Katie Himanga during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-67

7-c-RW
Appendix A

A-68

7-c-RW

(continued)

7-d-AR/CR/SW
Appendix A

A-69

The following pages contain the written comments

submitted by Mary Jackson during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-70

8-a-AR/PA/SW
Appendix A

A-71

8-a-AR/PA/SW 

(continued)
Appendix A

A-72

The following pages contain the comments

made by Ron Johnson during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-73

9-a-LR
Appendix A

A-74

9-a-LR 

(continued)
Appendix A

A-75

The following pages contain the written comments

submitted by Gina Lemon during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-76

10-a-CR
Appendix A

A-77

The following pages contain the written comments

submitted by Tom Lovejoy during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-78

11-a-AR

11-b-NS

11-c-AR/SW
Appendix A

A-79

11-d-EJ/SW

11-e-AR

11-f-CI
Appendix A

A-80

The following pages contain the comments

made by Joan Marshman during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-81

12-a-RW
Appendix A

A-82

12-a-RW

(continued)
Appendix A

A-83

The following pages contain the comments

made by Alan Muller during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-84

13-a-HH
Appendix A

A-85

13-b-LR
Appendix A

A-86

13-b-LR 

(continued)
Appendix A

A-87

13-c-ER/LR
Appendix A

A-88

13-d-LR

13-c-ER/LR 

(continued)
Appendix A

A-89

13-d-LR

(continued)

13-e-SD

13-f-OS
Appendix A

A-90

13-f-OS 

(continued)
Appendix A

A-91

13-f-OS 

(continued)

13-g-UR
Appendix A

A-92

13-g-UR

(continued)

13-h-RW
Appendix A

A-93

13-h-RW 

(continued)

13-i-AS
Appendix A

A-94

13-i-AS 

(continued)

13-j-HH
Appendix A

A-95

The following pages contain the comments

made by Carol Overland during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-96

14-a-LR
Appendix A

A-97

14-a-LR

(continued)

14-b-AS
Appendix A

A-98

14-b-AS

(continued)

14-c-LR
Appendix A

A-99

The following pages contain the written comments

submitted by the Prairie Island

Indian Community during the scoping period

for the Prairie Island Nuclear Generating Plant

license renewal 
Appendix A

A-100
Appendix A

A-101
Appendix A

A-102

15-a-ER
Appendix A

A-103

15-a-ER 

(continued)

15-b-LR
Appendix A

A-104

15-c-LR

15-d-HH/EJ

15-e-GW

15-b-LR 

(continued)
Appendix A

A-105

15-e-GW 

(continued)
Appendix A

A-106

15-e-GW

(continued)
Appendix A

A-107

15-e-GW

(continued)

15-f-HH/EJ

15-g-ER

15-h-HH
Appendix A

A-108

15-h-HH

(continued)
Appendix A

A-109

15-h-HH

(continued)

15-i-RW
Appendix A

A-110

15-i-RW 

(continued)
Appendix A

A-111

15-i-RW

(continued)

15-j-RW

15-k-AS

15-l-TR
Appendix A

A-112

15-l-TR

(continued)
Appendix A

A-113

15-l-TR 

(continued)

15-m-CR
Appendix A

A-114

15-m-CR

(continued)
Appendix A

A-115

15-m-CR

(continued)
Appendix A

A-116

15-m-CR

(continued)

15-n-TE
Appendix A

A-117

15-n-TE

(continued)
Appendix A

A-118

15-n-TE

(continued)

15-o-SE
Appendix A

A-119

15-o-SE

(continued)

15-q-SE

15-r-EJ

15-p-OS
Appendix A

A-120

15-r-EJ

(continued)

15-s-EJ

15-t-HH
Appendix A

A-121

15-u-PA
Appendix A

A-122

15-v-CI/OS/RW

15-w-OS/RW

15-x-ER

15-y-ER/LR
Appendix A

A-123

15-y-ER/LR

(continued)
Appendix A

A-124

15-z-CI/ER

15-aa-EJ

15-bb-EJ
Appendix A

A-125

15-bb-EJ

(continued)

15-cc-AS

15-dd-SW

15-ee-OS/SW
Appendix A

A-126

15-ff-OS

15-gg-HH

15-hh-OS
Appendix A

A-127
Appendix A

A-128
Appendix A

A-129
Appendix A

A-130

The following pages contain the comments

made by Michael Schultz during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-131

16-a-SR
Appendix A

A-132

16-a-SR

(continued)
Appendix A

A-133

16-a-SR

(continued)
Appendix A

A-134

The following pages contain the comments

made by Andrija Vukmir during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-135

17-b-SR

17-a-SN

17-c-SN
Appendix A

A-136

17-c-SN 

(continued)
Appendix A

A-137

17-d-RW

17-e-SR
Appendix A

A-138

The following pages contain the comments

made by Mike Wadley during the 

NRC public scoping meetings held on July 30, 2008 
Appendix A

A-139

18-a-SR
Appendix A

A-140

18-a-SR

(continued)
Appendix A

A-141

18-a-SR

(continued)

18-b-NS
Appendix A

A-142

18-b-NS 

(continued)
Appendix A

A-143

18-b-NS 

(continued)
Appendix A

A-144

18-c-NS

18-d-SR
Appendix A

A-145

18-d-SR 

(continued)

18-e-SR

18-f-SR
Appendix A

A-146

18-f-SR 

(continued)
Appendix A

A-147

Prairie Island Nuclear Generating Plant,

Units 1 and 2

Public Scoping Process

Comments and Responses

A.1. Alternative Energy Sources

The following comment pertains to the no-action alternative outlined by NEPA:

15-cc-AS

The NRC staff will address alternatives to the continued operation of PINGP 1 and 2, 

including the no-action alternative (not renewing the licenses) in Chapter 8 of the SEIS.

The following comments pertain to the scope of alternatives to be discussed in the 

DSEIS:

13-i-AS;15-k-AS

The NRC staff will evaluate environmental impacts associated with various reasonable 

alternatives to the continued operation of PINGP 1 and 2 in Chapter 8 of the SEIS.

The following comments pertain to using either natural gas or a combination of wind and 

natural gas to power an alternative to PINGP 1 and 2:

4-a-AS; 5-s-AS; 14-b-AS

The NRC staff will evaluate environmental impacts associated with various reasonable 

alternatives to the continued operation of PINGP 1 and 2 in Chapter 8 of the SEIS.

The following comment pertains to using the PINGP site for an alternate industrial 

purpose:

5-t-AS

The comment describes the potential conversion of the PINGP 1 and 2 site to an energy 

and research facility that would produce hydrogen in addition to providing electricity. The 

NRC staff’s examination of alternatives in Chapter 8 of the SEIS will be limited to energy 

alternatives that can replace or offset the capacity currently provided by PINGP 1 and 2. 

As PINGP 1 and 2 do not currently produce hydrogen or provide a site for energy 

research and development efforts, alternatives to continued operation of PINGP 1 and 2 

will not need to fulfill these roles. 

The following comment pertains to the greenhouse gas emissions and efficiency of 

energy generation technologies:

4-a-AS

The NRC staff will provide a comparison of greenhouse gas emissions from a variety of 

energy generation technologies in Chapter 6 of the SEIS. The NRC staff analysis of 

alternatives in Chapter 8 will also address relative levels of greenhouse gas emissions 

for alternatives.

The following comment pertains to policy or planning considerations in meeting future 

energy needs:

4-a-AS
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The NRC does not play a role in energy planning or energy policy development, though 

the NRC staff does take into account existing policies and regulations when evaluating 

energy alternatives.

A.2. Aquatic Resources

The following comment pertains to the impacts to aquatic resources from the 

impingement and entrainment of fish and shellfish:

11-a-AR

The comment is related to aquatic ecology, specifically impingement, entrainment, and 

heat shock analysis. As part of its environmental review process and SEIS, NRC will 

review and assess pertinent information regarding impingement, entrainment, and heat 

shock in Chapters 2 and 4 of the SEIS.

The following comment pertains to fish kills related to the cooling and intake systems of 

PINGP 1 and 2:

11-c-AR/SW

The comment is related to operation of the plant's cooling system, and its effects in 

terms of fish kills and other thermal impacts. Potential impacts associated with the 

plant's cooling system will be discussed in Chapter 4 of the SEIS. Additionally, NRC will 

identify potential mitigation measures to limit fish kill impacts in Chapter 4 of the SEIS.

The State, not the NRC, manages thermal impacts through the National Pollutant 

Discharge Elimination System (NPDES) permitting process. 

The following comments pertain to impacts from thermal discharges of the PINGP 1 and 

2 cooling systems:

4-b-AR/SW; 7-a-AR/RW/SW; 7-b-AR/CR/SW; 7-d-AR/CR/SW

These comments are related to operation of the plants cooling system, specifically the 

effects of the thermal discharge on aquatic and other resources. NRC will discuss the 

potential impacts associated with the plant’s thermal discharge will be presented in 

Chapter 4 of the SEIS. The State, not the NRC, regulates thermal discharges through 

the NPDES permitting process.

The following comment pertains to impacts to aquatic resources from exotic species:

11-e-AR

The comment is related to aquatic ecology. Invasive and exotic species as well as other 

impacts will be discussed in Chapters 2 and 4 of the SEIS. The State, not the NRC, 

regulates discharge contaminants through the NPDES permitting process. Additionally, 

Chapter 2 will provide a description of measures undertaken to control biofouling at 

PINGP 1 and 2.

The following comments pertain to the area of consideration for the aquatic ecology 

review and analysis provided in the SEIS:

5-e-AR; 8-a-AR/PA/SW

Issues pertaining to the area of consideration for review of aquatic ecology impacts are 

site specific, or Category 2 issues, and will be discussed in Chapters 2 and 4 of the 

SEIS.
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The following comment pertains to potential releases of radioactive materials into the 

water:

4-d-AR/HH

All nuclear plants were licensed with the expectation that they would release small 

quantities of radioactive material to both the air and water during normal operation.

Airborne and liquid releases of radionuclides from nuclear power plants must meet 

radiation dose-based limits specified in 40 CFR Part 190, 10 CFR Part 20, and the as 

low as is reasonably achievable (ALARA) criteria in 10 CFR Part 50, Appendix I.

Regulatory limits are placed on the radiation dose that members of the public might 

receive from all of the radioactive material released by the nuclear plant combined.

Licensees are required to report liquid, gaseous, and solid effluent releases as well as 

the results of their radiological environmental monitoring program annually to the NRC.

The annual effluent release and radiological environmental monitoring reports submitted 

to the NRC are available to the public through the ADAMS electronic reading room 

through the NRC website. The NRC routinely inspects all licensees to ensure their 

compliance with these regulatory limits.

Additionally, in the spring of 2006, the National Research Council of the National 

Academies published, “Health Risks from Exposure to Low Levels of Ionizing Radiation, 

BEIR VII Phase 2.” The major conclusion of the report is that current scientific evidence 

is consistent with the hypothesis that there is a linear, no-threshold dose response 

relationship between exposure to ionizing radiation and the development of cancer in 

humans. This conclusion is consistent with the system of radiological protection that the

NRC uses to develop its regulations. The NRC evaluated the BEIR VII report and 

discussed its findings in a report to the Commission (SECY 05-0202; Accession Number 

ML052640532). The NRC concluded that the BEIR VII report does not support the need 

for fundamental revision to the International Commission on Radiological Protection 

recommendations. Therefore, it is the NRC’s position that the NRC’s regulations 

continue to be adequately protective of public health and safety and the environment

and that none of the findings in the BEIR VII report warrant changes to the NRC 

regulations. The BEIR VII report does not say there is no safe level of exposure to 

radiation; it does not address “safe versus not safe.” It does continue to support the 

conclusion that there is some amount of cancer risk associated with any amount of 

radiation exposure and that risk increases with exposure and exposure rate. It does 

conclude that risk of cancer induction at the dose levels in NRC’s and EPA’s radiation 

standards is very small. Similar conclusions have been made in all of the associated 

BEIR reports since 1972 (BEIR I, III, and V). The comment does not provide any new 

and significant information and will not be evaluated further.

A.3. Cultural Resources

The following comments pertain to issues regarding potential impacts to cultural 

resources surrounding the PINGP 1 and 2 site and compliance with the National Historic 

Preservation Act:

7-b-AR/CR/SW; 7-d-AR/CR/SW; 10-a-CR; 15-m-CR;

The comments are related to the potential impacts to cultural, archaeological, and 

historical resources. NRC staff is aware of the Prairie Island Indian Community’s 

concern for the archaeological sites both on and within the vicinity of the PINGP 1 and 2 

facilities. The comments are noted, and the impacts of extended operation of the PINGP 
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1 and 2 on cultural, archaeological, and historical resources will be assessed and 

discussed in Chapters 2 and 4 of the SEIS. Additionally, the PIIC is a cooperating 

agency and will assist the NRC staff in its review. Several other tribes, the Bureau of 

Indian Affairs, and the Minnesota State Historic Preservation Office have been contacted 

by, and may provide their views to, the NRC under Section 106 of the National Historic 

Preservation Act.

A.4. Cumulative Impacts

The following comments pertain to the assessment of a cumulative impacts analysis in 

the SEIS:

5-g-CI/LR; 5-h-CI; 5-r-CI/LR; 5-q-CI/LR; 5-w-CI; 5-x-CI; 11-f-CI; 15-z-CI/ER

As part of the environmental review process, the NRC evaluates the potential for 

cumulative impacts of operations (as defined in 40 CFR 1508.7) during the renewal 

term. Chapter 4 of the SEIS will analyze the impacts of the proposed action in 

conjunction with other past, present, and reasonably foreseeable future actions at 

PINGP 1 and 2 and the activities of other industrial facilities and/or Federal agency 

actions in the area. As part of NRC's environmental review and SEIS, all pertinent 

information pertaining to cumulative impacts will be reviewed and assessed.

The following comments pertain to the cumulative impacts of spent fuel storage and 

spent fuel waste:

5-m-CI/RW; 5-o-CI/RW; 15-v-CI/OS/RW

Onsite storage of spent nuclear fuel is a Category 1 issue. Additionally, waste 

management issues were evaluated in the GEIS and determined to be a Category 1 

issue. Issues classified as Category 1 in Table B-1 of 10 CFR Part 51 have been 

determined in the GEIS to have similar impacts across all sites and are, therefore, not 

reevaluated in the SEIS unless new and significant information is identified that would 

lead the NRC staff to reevaluate the GEIS’s conclusions. During the environmental 

review, the NRC staff makes a concerted effort to determine whether any new and 

significant information exists for the specific site being evaluated that would change the 

generic conclusion for a Category 1 issue into a Category 2 issue. Category 2 issues are 

site specific issues which must be thoroughly analyzed by the applicant as part of its 

submittal and included in detail in its environmental report. The NRC staff then 

independently evaluates the issue as part of its SEIS.

While cumulative impacts are site specific issues for some resources, these comments 

pertaining to cumulative impacts of spent fuel storage and spent fuel waste are not 

within the scope of the environmental review and will not be evaluated further.

The following comments pertain to establishing a baseline for cumulative impacts in the 

areas of groundwater and hydrologic resources, human health, and aquatic resources:

5-r-CI/LR

Cumulative impacts on each of these resource areas are a Category 2 issue and will be 

addressed in Chapter 4 of the SEIS under cumulative impacts.
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A.5. Environmental Justice

The following comments pertain to the analysis of environmental justice within the SEIS:

6-b-EJ/UR; 6-f-EJ/RW/UR; 11-d-EJ/SW

The comments are noted. Environmental justice is an issue specific to the plant and will 

be addressed in Chapter 4 of the SEIS. To perform a review of environmental justice in 

the vicinity of the nuclear power plant, the NRC staff examines the geographic 

distribution of minority and low-income populations within 50 miles (80 km) of the site 

being evaluated. The staff uses the most recent census data available. Once the 

locations of minority and low-income populations are identified, the staff determines the 

extent to which these populations may be disproportionately affected.

The environmental impacts of various individual operating uranium fuel cycle facilities

are outside the scope of license renewal but are addressed in separate EISs prepared

by NRC. These documents include analyses that address human health and 

environmental impacts to minority and low-income populations. Electronic copies of 

these EISs are available through the NRC’s public Web site under Publications Prepared 

by NRC Staff document collection of the NRC’s Electronic Reading Room at 

http://www.nrc.gov/reading-rm/doc-collections/; and the NRC’s Agency wide Documents 

Access and Management System (ADAMS) at http://www.nrc.gov/readingrm/adams.html

The following comments pertain specifically to the Prairie Island Indian Community 

(PIIC), and the inclusion of the PIIC in the analysis of environmental justice within the 

SEIS:

.

5-f-EJ/RW; 15-d-HH/EJ; 15-f-HH/EJ; 15-r-EJ; 15-s-EJ; 15-aa-EJ; 15-bb-EJ; 

The PIIC is a minority population living within the 50 mile (80 km) radius of PINGP 1 and 

2. PIIC will be included in the environmental justice analysis in Chapter 4 of the SEIS. 

Additionally, the PIIC is a cooperating agency and will assist the NRC staff in its review 

of environmental justice issues.

A.6. Environmental Report

The following comments raise concerns pertaining to the information included within the 

Environmental Report submitted by the applicant:

3-c-ER/HH; 5-a-ER; 6-i-ER/HH;13-c-ER/LR; 15-a-ER;15-g-ER; 15-x-ER; 15-y-ER/LR; 15-zCI/ER

The comments assert that the Environmental Report failed to include information 

regarding the impacts of routine releases of radioactive effluents, the effects of 

continued operations on the health and on the Prairie Island Indian Community, the 

effects of the plant’s requested power uprate, the expansion of dry cask storage, and the 

replacement of the steam generator. The comments will be considered, as appropriate, 

during the environmental review for the license renewal of PINGP 1 and 2.

A.7. Groundwater

The following comments pertain indirectly and cumulatively to impacts to the 

groundwater resources, mostly from tritium, surrounding PINGP 1 and 2:
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A-152

5-b-GW/SW; 15-e-GW

Groundwater is a Category 2 issue and discussed in Chapters 2 and 4 of the SEIS. The 

comments, in general, are related to the public concerns regarding potential leaks at 

PINGP 1 and 2 and the PIIC’s as well as the public's request for additional information 

and monitoring data on the level and extent of potential environmental impacts. The 

requirement to obtain additional data and information on known leaks is part of the 

ongoing operating license and is currently being addressed by NRC and the applicant.

The comments, as they pertain to requiring additional environmental data, are not within 

the scope of the environmental review. However, the environmental impacts of identified 

leaks are within the scope of the environmental review and will be addressed in 

Chapters 2 and 4 of the SEIS.

In addition, NRC regulations require licensees to make surveys, as necessary, to 

evaluate the potential hazard of radioactive material released in order to assess doses to 

members of the public and workers, recent discoveries of releases at other plants 

indicate that undetected leakage to groundwater from facility structures, systems, or 

components can occur resulting in unmonitored and unassessed exposure pathways to 

members of the public. The NRC has identified several instances of unintended tritium 

releases, and all available information shows no threat to the public. Nonetheless, the 

NRC is inspecting each of these events to identify the cause, verify the impact on public 

health and safety, and review licensee plans to remediate the event. The NRC also 

established a lessons learned task force to address inadvertent, unmonitored liquid 

radioactive releases from U.S. commercial nuclear power plants. This task force 

reviewed previous incidents to identify lessons learned from these events and determine 

what, if any, changes are needed to the regulatory program. Detailed information and 

updates on these liquid releases can be found on the NRC public website at 

http://www.nrc.gov/reactors/operating/ops-experience/grndwtr-contam-tritium.htm.

A.8. Human Health

The following comments pertain to the assessment of human health impacts in the SEIS:

3-c-ER/HH; 4-d-AR/HH; 6-a-HH; 6-c-HH; 6-d-HH; 6-e-HH; 6-h-HH/LR; 13-a-HH; 13-j-HH; 15-dHH/EJ; 15-f-HH/EJ; 15-h-HH

The NRC staff will address the radiological impacts to human health during its evaluation 

of the PINGP 1 and 2 license renewal application. However, this issue is a Category 1 

issue. Issues classified as Category 1 in Table B-1 of 10 CFR Part 51 have been 

determined in the GEIS to have similar impacts across all sites and are, therefore, not 

reevaluated in the SEIS unless new and significant information is identified that would 

lead the NRC staff to reevaluate the GEIS’s conclusions. During the environmental 

review, the NRC staff makes a concerted effort to determine whether any new and 

significant information exists for the specific site being evaluated that would change the 

generic conclusion for a Category 1 issue into a Category 2 issue. Category 2 issues are 

site specific issues which must be thoroughly analyzed by the applicant as part of its 

submittal and included in detail in its Environmental Report. The NRC staff then 

independently evaluates these issues as part of its SEIS.
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The following comments pertain to the monitoring of radioactive effluents:

3-b-HH; 3-c-ER/HH 4-e-HH; 6-a-HH; 6-c-HH; 6-d-HH; 6-e-HH; 6-h-HH/LR; 6-i-ER/HH; 13-j-HH; 

15-h-HH

The applicant’s current operating license requires it to conduct environmental monitoring 

programs. Upon identification of a new pathway of potential radiological release, the 

applicant is required by 10 CFR Part 20 to perform radiological surveys to evaluate the 

radiological hazard from the release. While current operating issues are outside of the 

scope of the environmental review of this license renewal application, the NRC staff will 

consider the radioactive effluents monitoring and release points as part of its evaluation 

of the PINGP license renewal application. The staff will perform a historical review of the 

radioactive effluents released from the plant and of the data from the applicant’s 

radiological environmental monitoring program to determine if there are any significant or 

unusual trends that warrant additional evaluation. NRC's environmental review is 

confined to environmental matters relevant to the extended period of operation 

requested by the applicant. Radiological data relevant to the environmental review will 

be discussed as appropriate in Chapters 2 and 4 of the SEIS.

This issue is a Category 1 issue. Issues classified as Category 1 in Table B-1 of 10 CFR 

Part 51 have been determined in the GEIS to have similar impacts across all sites and 

are, therefore, not reevaluated in the SEIS unless new and significant information is 

identified that would lead the NRC staff to reevaluate the GEIS’s conclusions. During the 

environmental review, the NRC staff makes a concerted effort to determine whether any 

new and significant information exists for the specific site being evaluated that would 

change the generic conclusion for a Category 1 issue into a Category 2 issue. Category 

2 issues are site specific issues which must be thoroughly analyzed by the applicant as 

part of its submittal and included in detail in its Environmental Report. The NRC staff 

then independently evaluates these issues as part of its SEIS.

NRC regulations require licensees to control and limit releases to the environment (the 

air and water) to very small amounts. As part of the NRC requirements for operating a 

nuclear power facility, licensees must keep releases of radioactive material to 

unrestricted areas during normal operation as low as is reasonably achievable (as 

described in the NRC’s regulations in 10 CFR Part 50.34a) and comply with radiation 

dose limits for the public as given in the regulations in 10 CFR Part 20.

In addition, NRC regulations require licensees to have various effluent and

environmental monitoring programs so that the impacts from plant operations are 

minimized and the extent of releases are accurately recorded and reported. The NRC 

requires licensees to report plant discharges and results of environmental monitoring 

around their plants to ensure that potential impacts are detected and reviewed.

Licensees must also participate in an interlaboratory comparison program, which 

provides an independent check of the accuracy and precision of environmental 

measurements. Licensees are required to keep accurate records on releases to the air 

and water. In annual reports, licensees identify the amount of liquid and airborne 

radioactive effluents discharged from plants and calculate associated doses. Licensees 

also must report environmental radioactivity levels around their plants annually. These 

reports, which are available to the public, include sampling from thermoluminescent 

dosimeters (which measure radiation dose levels); airborne radioiodine and particulate 

samplers; samples of surface, groundwater, and drinking water and downstream 

shoreline sediment from existing or potential recreational facilities; and samples of 

ingestion sources such as milk, fish, invertebrates, and broad-leaf vegetation. The NRC 
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A-154

conducts periodic onsite inspections of each licensee’s effluent and environmental 

monitoring programs to ensure compliance with NRC requirements. The NRC 

documents licensee effluent releases and the results of their environmental monitoring 

and assessment effort in inspection reports that are available to the public.

The following comments pertain to exposure from electromagnetic fields (EMF):

15-gg-HH

The NRC staff will evaluate the actions taken by PINGP to ensure that the impacts from 

acute electromagnetic fields from their power lines adhere to safety standards issued by 

the National Electrical Safety Code. These safety standards are designed to ensure that 

any impacts remain within acceptable limits. This is a Category 2 issue that every plant 

seeking license renewal must address in its Environmental Report. The NRC staff will 

include a discussion of PINGP 1 and 2’s program to manage acute electromagnetic 

fields in Chapters 2 and 4 of the SEIS.

For impacts related to the chronic exposure to electromagnetic fields, biological and 

physical studies of 60-Hz electromagnetic fields have not found consistent evidence 

linking harmful effects with field exposures. There is currently no scientific consensus on 

this issue. Therefore, the NRC staff will not perform a specific health assessment for 

chronic exposure to EMF in the SEIS.

The following comments pertain to human health issues generically associated with

nuclear power generating facilities:

3-b-HH; 3-c-ER/HH; 15-h-HH

The GEIS evaluated human health issues and determined them to be a Category 1 

issue. The amount of radioactive material released from nuclear power facilities is well 

measured, well monitored, and known to be very small. The doses of radiation that are 

received by members of the public as a result of exposure to nuclear power facilities are 

so low that resulting cancers have not been observed and would not be expected. A 

number of studies of cancer incidence in the vicinity of nuclear power facilities have 

been conducted and there are no studies to date that are accepted by the scientific 

community that show a correlation between radiation dose from nuclear power facilities 

and cancer incidence in the general public. The comments are noted but provide no new 

and significant information and will not be evaluated further.

The following comments pertain to added risk due to proximity to PINGP 1 and 2:

4-e-HH; 15-d-HH/EJ

Human health issues were evaluated in the GEIS and were determined to be Category 1 

issues. The GEIS evaluated radiation exposures to the public for all plants including 

PINGP 1 and 2, and concluded that the impact was small. The information regarding 

increases in the population around PINGP 1 and 2, possible changes in the age 

distribution of that population, and increased radio-sensitivity of older people and other 

sensitive populations does not change this evaluation. The maximum dose to any 

member of the public living or working near PINGP 1 and 2 is well below one millirem 

per year, which is well below the radiation standards set by EPA and NRC. These 

comments provide no new and significant information regarding human health issues 

and therefore will not be evaluated further.

The following comment pertains to the BEIR VII Phase 2 report:

3-c-ER/HH
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A-155

In the spring of 2006, the National Research Council of the National Academies 

published, “Health Risks from Exposure to Low Levels of Ionizing Radiation, BEIR VII 

Phase 2.” The major conclusion of the report is that current scientific evidence is 

consistent with the hypothesis that there is a linear, no-threshold dose response 

relationship between exposure to ionizing radiation and the development of cancer in 

humans. This conclusion is consistent with the system of radiological protection that the 

NRC uses to develop its regulations. The NRC evaluated the BEIR VII report and 

discussed its findings in a report to the Commission (SECY 05-0202; ADAMS No.

ML052640532). The NRC concluded the BEIR VII report does not support the need for 

fundamental revision to International Commission on Radiological Protection 

recommendations. Therefore, the NRC’s regulations continue to be adequately 

protective of public health and safety and the environment. None of the findings in the 

BEIR VII report warrant changes to the NRC regulations. The BEIR VII report does not 

say there is no safe level of exposure to radiation; it does not address “safe versus not 

safe.” It does continue to support the conclusion that there is some amount of cancer 

risk associated with any amount of radiation exposure and that risk increases with 

exposure and exposure rate. It does conclude that risk of cancer induction at the dose 

levels in NRC’s and EPA’s radiation standards is very small. Similar conclusions have 

been made in all of the associated BEIR reports since 1972 (BEIR I, III, and V). The 

comment does not provide any new and significant information and will not be evaluated 

further.

The following comment pertains to non-radiological human health concerns:

15-t-HH

The GEIS evaluated human health issues related to plant operations during the period of 

extended operations and determined that the issues are generic Category 1 issues.

These issues include both radiological and non-radiological health effects. The comment 

is noted but because it provides no new and significant information, it will not be 

evaluated further.

A.9. License Renewal and its Processes

The following comments pertain to the MOU between the NRC and the PIIC:

9-a-LR; 15-b-LR; 15-c-LR 

The NRC and the PIIC signed an MOU pursuant to which the PIIC is a cooperating 

agency and the NRC is the lead agency in four specific resource areas: environmental 

justice, land use, cultural resources, and historic and archeological resources. The MOU 

can be accessed through the NRC’s Electronic Reading Room via ADAMS at accession 

number ML081710160. These scoping comments are general in nature and do not 

provide new information. Therefore, the comments will not be evaluated further.

The following comments pertain to the public’s ability to provide public comments and 

the time allotted for the public to do so:

3-a-LR; 5-g-CI/LR; 6-g-LR; 9-a-LR; 14-c-LR

The NRC has established an open process to permit all members of the public to 

participate in the environmental scoping process. The NRC published a Federal Register 

Notice (FRN) of its intent to conduct environmental scoping pertaining to the PINGP 1 

and 2 license renewal application on July 22, 2008. The environmental scoping period 

lasted for two months and closed on September 22, 2008. In this time, the NRC staff 
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held two public meetings on July 30, 2008, to receive comments on the scope of the 

environmental review. These meetings were advertised on the NRC public website, in 

local newspapers, on notices posted throughout Red Wing, and by letter to individuals 

and groups on the NRC’s most current distribution list.

The NRC makes every effort to inform interested persons or parties of their opportunity 

to be involved in the NEPA process. After the draft SEIS is published, the NRC staff will 

issue a FRN of the availability of the document, and this FRN will also open a 75-day 

period to comment on the draft SEIS. Additionally, the NRC staff will hold a public 

meeting to receive comments on the draft SEIS. Comments can be provided to the NRC 

in person, by mail, and by e-mail. These scoping comments identified above are general 

in nature and do not provide new information. Therefore, the comments will not be 

evaluated further.

The following comments pertain to the regulations and procedures regarding NRC staff’s 

review of information, assessment, and analysis during the environmental review 

process, as well as the availability of information to the public:

5-q-CI/LR; 6-h-HH/LR; 13-b-LR

Pertaining to the staff’s regulations on the environmental review process under NEPA, 

10 CFR 51 contains the NRC regulations that implement NEPA. These regulations 

define the NRC staff’s scope of review and its analysis of information in the SEIS. 

Regarding the availability of information to the public, the NRC is required to protect 

information deemed sensitive. Before any NRC- or licensee-generated materials can be 

released for public inspection, the NRC must complete a sensitivity review to ensure the 

documents do not contain information that should be designated sensitive.

The following comments pertain to the environmental review process, how it determines 

impacts on the environment, and how NRC staff should prepare its SEIS:

5-c-LR; 5-r-CI/LR; 5-u-LR; 5-v-LR; 15-y-ER/LR

As part of the environmental review process, the NRC evaluates site-specific data 

provided by the applicant, other Federal agencies, State agencies, tribal and local 

governments, as well as information from members of the public. In addition, the NRC 

performs independent reviews of the plant-specific environmental impacts of license 

renewal in accordance with NEPA and the NRC’s requirements in 10 CFR Part 51. The 

following technical areas are commonly included in the review: land use, ground and 

surface water use, ground and surface water quality, air quality, aquatic resources, 

terrestrial resources, threatened and endangered species, radiological impacts, 

socioeconomic factors, environmental justice issues, historical and archaeological 

resources, related federal project activities, postulated accidents, uranium fuel cycle and 

solid waste management, decommissioning, alternatives to license renewal, and 

irreversible or irretrievable resource commitments. Site specific Category 2 impacts will 

be discussed in Chapter 4 of the SEIS. Other areas may be included as a result of 

information obtained during the NRC staff’s review or from public comments during or 

following meetings that are held in the vicinity of the nuclear power reactor.

The following comments pertain to the availability of the applicant’s license renewal 

application:

13-c-ER/LR; 13-d-LR; 14-a-LR

10 CFR 51.66 specifies the requirements for availability and distribution of the 

applicant’s environmental reports required by the applicant. In addition to providing 
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copies to the NRC, applicants must maintain the capability to generate additional copies 

of the environmental report for distribution to Federal, State, and local officials, and any 

affected Indian tribes. Applicants are not required to provide copies of the application to 

other interested persons or parties. However, once a license renewal application is 

accepted for review by the NRC, the publicly available portions of the application are 

included on the NRC’s website on the license renewal webpage at 

http://www.nrc.gov/reactors/operating/licensing/renewal.html

ADAMS. The ADAMS Public Electronic Reading Room is accessible at

under the link entitled, 

“Status of Current Applications and Industry Initiatives.” Applications are also available 

for public inspection in the NRC Public Document Room (PDR), located at One White 

Flint North, 11555 Rockville Pike, Rockville, Maryland, 20852, or from the NRC’s 

A.10. Nuclear Safety

http://www.nrc.gov/reading-rm/adams/web-based.html. Copies of the application are 

also available at the Red Wing public library.

The following comments pertain to nuclear safety, the safety of operations at PINGP 1 

and 2, and the safety of fuel storage:

5-z-NS; 11-b-NS; 18-b-NS; 18-c-NS

The NRC's environmental review is confined to environmental matters relevant to the 

20-year period of extended period of operation requested by the applicant. Operational 

safety issues and issues related to the safety of fuel storage are outside the scope of 

10 CFR Part 51 and Part 54 and will not be evaluated further in the SEIS. The 

comments provide no new information and, therefore, will not be evaluated further in the 

context of the environmental review.

A.11. Outside of Scope

The following comment pertains to general background information about the NEPA

process:

5-l-OS

The comment provides general background information and is outside of the scope of 

the environmental review process and, therefore, will not be evaluated further.

The following comments pertain to a proposed license amendment request regarding 

transition to a new fuel type at PINGP 1 and 2:

5-y-OS/RW; 13-f-OS

License amendment requests completed during the original 40 year term or during the 

term of extended operation if the license renewal is granted are reviewed by the NRC for 

any environmental or safety concerns at the time of the amendment. These comments 

are outside of the scope of the environmental review process and, therefore, will not be 

evaluated further.
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The following comments pertain to the extended power uprate proposal by NSP and 

issues of electricity supply:

5-i-OS; 5-k-OS/RW; 5-y-OS/RW; 15-p-OS; 15-v-CI/OS/RW; 15-w-OS/RW; 15-ee-OS/SW; 15-ffOS

The purpose and need for the proposed action (renewal of an operating license) is to 

provide an option that allows for power generation capability beyond the term of the 

current nuclear power plant operating license to meet future system generating needs, 

as such needs may be determined by State, utility, and where authorized, Federal (other 

than NRC) decision makers. The NRC does not assess the need for power as part of its 

license renewal environmental review, and 10 CFR 51.95(c)(2) provides that the SEIS is 

not required to discuss such need. 

With respect to power uprates or any modifications made to increase power, these 

actions are not within the scope of license renewal and they require a separate licensing 

action. The NRC staff would prepare an Environmental Assessment (EA), or an EIS, if 

needed, for the power uprate application. These comments provide no new and 

significant information and will not be evaluated further.

The following comment pertains to issues surrounding security and terrorism:

15-hh-OS

Security issues such as safeguards planning are not tied to license renewal, but are 

considered to be issues that need to be dealt with constantly as a part of the current 

operating license. Security issues are periodically reviewed and updated (and extended) 

at every operating plant. These reviews will continue throughout the period of any 

extended license. If issues related to security are discovered at a nuclear plant, they 

would be addressed immediately, and any necessary changes reviewed and 

incorporated under the operating license, rather than waiting for the period of extended 

operation. The NRC's environmental review is confined to environmental matters 

relevant to the extended period of operation requested by the applicant. Appropriate 

safeguards and security measures have been incorporated into the site security and 

emergency preparedness plans. Any required changes to emergency and safeguard 

contingency plans related to terrorist events will be incorporated and reviewed under the 

operating license. The comments provide no new information and do not pertain to the 

scope of license renewal as defined under 10 CFR Part 51 and 54. Therefore, the 

comment will not be evaluated further.

A.12. Postulated Accidents

The following comments pertain to the severe accident mitigation alternatives (SAMA) 

analysis:

8-a-AR/PA/SW; 15-u-PA

The comments are related to the impacts of design basis accidents and severe 

accidents. The impacts of design basis accidents and severe accidents were evaluated 

in the GEIS and determined to be small for all plants; therefore, they are Category 1 

issues. Technical issues classified as Category 1 in Table B-1 of 10 CFR Part 51 have 

been generically evaluated in the GEIS and are not reevaluated in the SEIS unless new 

and significant information is identified that would lead the NRC staff to reevaluate the 

GEIS’s conclusions. During the environmental review, the NRC staff makes a concerted 

effort to determine whether any new and significant information exists for the specific site 
Appendix A

A-159

being evaluated that would change the generic conclusion for a Category 1 issue into a 

Category 2 issue. Category 2 issues are site specific issues which must be thoroughly 

analyzed by the applicant as part of its submittal and included in detail in its 

environmental report. The NRC staff then independently evaluates the issue as part of 

its SEIS.

However, alternatives to mitigate severe accidents must be considered for all plants that 

have not considered such alternatives. During the plant-specific environmental review of 

PINGP 1 and 2, the NRC will determine whether there is any new and significant 

information bearing on the previous analysis in the GEIS. The applicant provided a 

severe accident mitigation alternatives (SAMA) analysis as part of the license renewal 

application for PINGP 1 and 2. The NRC staff’s review of the SAMA analysis will be 

discussed in Chapter 5 and Appendix F of the SEIS for PINGP 1 and 2.

Concerning the potential for accidental drawdown at Lock and Dam 3, this scenario is 

outside the scope of the environmental review and will not be considered further. 

Concerning the effects of a severe accident on the Prairie Island Indian Community 

specifically, socioeconomic issues, including disproportionate effects to minority or lowincome communities, will be discussed in Chapters 2 and 4 of the SEIS.

A.13. Radioactive Waste

The following comments pertain to long term storage of spent fuel:

5-j-RW; 5-k-OS/RW; 5-m-CI/RW; 5-n-RW; 5-o-CI/RW; 5-p-RW; 5-y-OS/RW; 5-aa-RW; 6-fEJ/RW/UR; 7-a-AR/RW/SW; 7-c-RW; 12-a-RW; 13-h-RW; 15-i-RW; 15-j-RW; 15-v-CI/OS/RW; 

17-d-RW

Onsite storage of spent nuclear fuel is a Category 1 issue and the safety and 

environmental effects of long-term storage of spent fuel onsite has been evaluated by 

the NRC in the Waste Confidence Rule. The Commission believes there is reasonable 

assurance that at least one mined geologic repository will be available within the first 

quarter of the twenty-first century, and sufficient repository capacity will be available 

within 30 years beyond the licensed life for operation of any reactor to dispose of the 

commercial high-level waste and spent fuel originating in such reactor and generated up 

to that time. In its Statement of Considerations for the 1990 update of the Waste 

Confidence Rule (55 FR 38472), the Commission addressed the impacts of the disposal 

of spent fuel discharged from the current fleet of reactors operating under existing and 

renewed licenses and from a new generation of operating reactors. The rule was last 

reviewed by the Commission in 1999 when it reaffirmed the findings in the rule (64 FR 

68005). The rule is currently the subject of a notice of proposed rulemaking (73 FR 

59547) that proposes to simplify the rule to state that spent fuel can be “stored safely 

and without significant environmental impacts beyond the licensed life for operation 

(which may include the term of a revised or renewed license) of that reactor at its spent 

fuel storage basin or at either onsite or offsite ISFSIs until a disposal facility can 

reasonably be expected to be available.” Because the issue of spent fuel storage is a 

Category 1, generic issue, comments regarding spent fuel storage are not within the 

scope of the environmental review and will not be evaluated further.

The following comments pertain to the Independent Spent Fuel Storage Installation 

(ISFSI) system in place at PINGP 1 and 2:

5-f-EJ/RW; 5-k-OS/RW; 5-y-OS/RW; 15-i-RW; 15-v-CI/RW; 15-w-OS/RW
Appendix A

A-160

The comments relate to spent fuel management and storage issues specifically those 

regarding the PINGP 1 and 2 independent spent fuel storage installation (ISFSI). Waste 

management issues and onsite storage of spent nuclear fuel were evaluated in the GEIS 

and determined to be a Category 1 issue. In addition, the safety and environmental 

effects of long-term, onsite, storage of spent fuel onsite was addressed by the NRC, in 

the Waste Confidence Rule (10 CFR 51.23). In the Waste Confidence Rule, Finding 4, 

the Commission determined that spent fuel can be stored onsite for at least 30 years 

beyond the licensed operating life, which may include the term of a renewed license. At 

or before the end of that period, the rule asserts that spent fuel will be moved to a 

permanent repository. In October 2008, the NRC proposed to revise Finding 4 in the 

Waste Confidence Decision so that it reads as follows: “The Commission finds 

reasonable assurance that, if necessary, spent fuel generated in any reactor can be 

stored safely without significant environmental impacts for at least 60 years beyond the 

licensed life for operation (which may include the term of a revised or renewed license) 

of that reactor in a combination of storage in its spent fuel storage basin and either 

onsite or offsite independent spent fuel storage installations.”

The GEIS is based on the assumption that storage of the spent fuel onsite is not 

permanent. The SEIS for PINGP 1 and 2, is based on the same assumption. 

With respect to the PINGP 1 and 2 ISFSI, specifically, any modifications to the ISFSI 

pad or containers themselves may require separate licensing actions. NRC regards 

these actions as part of the current operating licenses and thus they fall outside of the 

scope of license renewal. These comments provide no new and significant information 

and will not be evaluated further.

A.14. Shutdown and Decommissioning

The following comment pertains to how much time is budgeted for relicensing, and 

whether or not PINGP 1 and 2 should be decommissioned:

13-e-SD

The NRC makes its decision whether or not to renew the license based on safety and 

environmental considerations. The final decision on whether or not to decommission the 

nuclear plant will be made by the utility, state, and federal (non-NRC) decision makers. 

This final decision may be based on economics, energy reliability goals, environmental 

considerations and potential impacts, and other objectives over which the other entities 

may have jurisdiction. 

The environmental review generally takes 22 months to complete if no hearing is 

granted and 30 months if a hearing is granted.

Environmental impacts from the activities associated with the decommissioning of any 

reactor before or at the end of an initial or renewed license are evaluated in the GEIS 

and in NUREG-0586, Generic Environmental Impact Statement for Decommissioning 

Nuclear Facilities, Supplement 1, Regarding the Decommissioning of Nuclear Power 

Reactors, published in 2002. The findings from these two documents are used to 

support the findings in the SEIS by the use of tiering. Tiering is a process by which 

agencies eliminate repetitive discussions and focus on the more pertinent issues. The 

effect of license renewal on the impacts of decommissioning will be discussed in 

Chapter 7 of the SEIS.
Appendix A

A-161

A.15. Socioeconomics

The following comments pertain to NRC staff’s assessment of socioeconomics:

4-c-SE; 5-d-SE; 15-o-SE; 15-q-SE

The comments are related to the socioeconomic impacts associated with the continued 

operation or closure of PINGP 1 and 2. Socioeconomic impacts such as housing, 

transportation, taxes, employment, and land use are Category 2 issues. These issues 

will be addressed in Chapters 2 and 4 of the SEIS.

A.16. Support for License Renewal

The following comments pertain to the support of PINGP 1 and 2 license renewal:

16-a-SR; 17-b-SR; 17-e-SR

The comments are in support of license renewal of PINGP 1 and 2, and are general in 

nature. In addition, 10 CFR 51.95(c)(2) discussed the need for power, which is outside of 

the scope of license renewal. These comments provide no new and significant 

information and will not be evaluated further.

The following comments pertain to the support of Xcel Energy and NMC:

1-a-SR; 2-a-SR; 16-a-SR; 18-a-SR; 18-d-SR; 18-e-SR; 18-f-SR

The comments are in support of Xcel/NSP (formerly NMC/Xcel) and/or their 

philanthropic activities. The comments are outside of the scope of the staff’s 

environmental review and will not be evaluated further.

A.17. Support for Nuclear Power

The following comments are in support of nuclear power, generally:

17-a-SN; 17-c-SN

The need for power is outside of the scope of license renewal and pursuant to 10 CFR 

51.95(c)(2), need not be addressed in this SEIS. The purpose and need for the 

proposed action (renewal of the PINGP 1 and 2 operating license) is to provide an option 

that allows for power generation capability beyond the term of the current operating 

licenses and thereby meet future system generating needs, as such needs may be 

determined by State, utility, and where authorized, Federal (other than NRC) decision 

makers. These comments are outside the scope of the staff’s environmental review and 

will not be evaluated further.

A.18. Surface Water

The following comments pertain to the effects of thermal discharge on the Mississippi 

River and other surface waterbodies:

4-b-AR/SW; 4-f-SW; 7-a-AR/RW/SW; 7-b-AR/CR/SW; 7-d-AR/CR/SW; 11-c-AR/SW; 11-dEJ/SW

The comments are related to operation of the plants’ cooling system, specifically the 

effects of thermal discharge on surface water, and aquatic and other resources. A 

discussion of the potential impacts associated with the plants thermal discharge will be 

presented in Chapter 4 of the SEIS.
Appendix A

A-162

The following comments pertain to protecting the surface water resources as well as 

assessing impacts to surface water resources near PINGP 1 and 2:

4-b-AR/SW; 5-b-GW/SW; 15-dd-SW

Water use and water quality issues are Category 2 issues and will be addressed in 

Chapters 2 and 4 of the SEIS.

The following comments pertain to Lock and Dam 3, a U.S. Army Corps of Engineers 

owned and operated facility and associated erosion impacts:

8-a-AR/PA/SW; 15-ee-OS/SW

Issues pertaining to the construction and safety of Lock and Dam 3 are not within the 

scope of review for license renewal. However, concerns relating to the Mississippi River 

and other surface waterbodies near PINGP 1 and 2 will be addressed in Chapter 4 of the 

SEIS. Issues pertaining to water use and quality, including erosion, are Category 2 

issues and will be addressed in Chapters 2 and 4 of the SEIS.

A.19. Terrestrial Resources

The following comment pertains to impacts to avian mortality within the transmission 

line corridors surrounding PINGP 1 and 2:

15-l-TR

Impacts from bird collisions with transmission lines was determined to be a Category 1 

issue in the GEIS. Technical issues classified as Category 1 in Table B-1 of 10 CFR Part 

51 have been generically evaluated in the GEIS and are not reevaluated in the SEIS 

because the conclusions reached would be the same as in the GEIS, unless new and 

significant information is identified that would lead the NRC staff to reevaluate the 

GEIS’s conclusions. During the environmental review, the NRC staff makes a concerted 

effort to determine whether any new and significant information exists for the specific site 

being evaluated that would change the generic conclusion for a Category 1 issue into a 

Category 2 issue. This study, as well as other pertinent information concerning this 

issue, will be discussed in Chapter 4 of the SEIS. However, this issue will remain 

Category 1 unless the NRC staff finds new and significant information during the 

environmental review.

Impacts to terrestrial ecology and non-threatened and endangered species are a 

Category 1 issue. Impacts to threatened and endangered species, including any 

protected avian species, is a Category 2 issue and will be addressed in Chapters 2 and 

4 of the SEIS.

A.20. Threatened and Endangered Species and Essential Fish Habitat

The following comment pertains to the threatened and endangered Higgins eye 

pearlymussel:

15-n-TE

The potential impacts of the continued operation of PINGP 1 and 2 on threatened and 

endangered species is a site specific, or Category 2 issue and will be addressed in 

Chapters 2 and 4 of the SEIS under aquatic resources. Further, NRC staff will issue a 

Biological Assessment on the Higgins eye pearlymussel, which can be found in 

Appendix D of the draft SEIS. 
Appendix A

A-163

A.21. Uranium Fuel Cycle

The following comments pertain to the uranium fuel cycle and waste management:

6-b-EJ/UR; 6-f-EJ/RW/UR; 13-g-UR

The NRC evaluated the impacts of the uranium fuel cycle which comprises uranium 

mining and milling, the production of uranium hexafluoride, isotopic enrichment, fuel 

fabrication, reprocessing of irradiated fuel, transportation of radioactive materials and 

management of low level wastes and high level wastes related to uranium fuel cycle 

activities. The wide range of activities associated with the uranium fuel cycle are 

geographically located throughout the United States and affect a diverse population. The 

impacts on the environment of the uranium fuel cycle is a Category 1 issue. Technical 

issues classified as Category 1 in Table B-1 of 10 CFR Part 51 have been generically 

evaluated in the GEIS and are not reevaluated in the SEIS because the conclusions 

reached would be the same as in the GEIS, unless new and significant information is 

identified that would lead the NRC staff to reevaluate the GEIS’s conclusions. During the 

environmental review, the NRC staff makes a concerted effort to determine whether any 

new and significant information exists for the specific site being evaluated that would 

change the generic conclusion for a Category 1 issue into a Category 2 issue. Category 

2 issues are site-specific issues which must be thoroughly analyzed by the applicant as 

part of its submittal and included in detail in its Environmental Report. The NRC staff 

then independently evaluates the issue as part of its SEIS.

The NRC has conducted several transportation studies to evaluate the risk of 

transportation of radioactive material. NUREG-0170 (NRC 1977b), supported NRC's 

10 CFR Part 71, "Packaging and Transportation of Radioactive Material" rulemaking. 

Based on this study, the Commission concluded that the transportation regulations are 

adequate to protect the public against unreasonable risks from the transportation of 

radioactive materials, including spent fuel. The NRC sponsored another study in the 

1980s entitled, "Shipping Container Response to Severe Highway and Railway Accident 

Conditions," NUREG/CR-4829 (Fischer et al. 1987), or the "Modal Study." Based on the 

results of this study, the NRC staff concluded that NUREG-0170 overestimated spent 

fuel accident risks by about a factor of three. In March 2000, the NRC initiated another 

spent fuel study, "Reexamination of Spent Fuel Shipment Risk Estimates," NUREG/CR6672 (Sprung et al. 2000). This study focused on risks of a modern spent fuel transport 

campaign from reactor sites to possible interim storage sites and/or permanent geologic 

repositories. This study concluded that accident risks were much less than those 

estimated in NUREG-0170 and that more than 99 percent of transportation accidents are 

not severe enough to damage NRC-certified spent fuel casks. While very severe 

accidents could cause cask damage, the studies show that releases of material would 

be small and pose little risk to the local population/public. The most severe accidents 

might cause greater releases, but their likelihood is so remote that the NRC considers 

the risk to public health to be low. The comments are noted. However, they do not 

provide any new and significant information and will not be evaluated further.
Appendix A

A-164

APPENDIX A – COMMENTS ON DRAFT SUPPLEMENTAL ENVIRONMENTAL IMPACT 

STATEMENT

During the comment period, the NRC staff received seven letters and two e-mails with 

comments on the draft SEIS. Additionally, comments were received from four individuals during 

the public meeting held on December 17, 2009, at the Red Wing Public Library, Red Wing, MN. 

The following table lists the name of the person making the comment, their affiliation (if any), 

and the ADAMS Accession Number. Table 2 contains the list of technical issue categories to 

which the comments have been divided. Each comment has been given a unique identifier 

which includes the Commenter ID Number and technical issue abbreviation code.

Table 1 – Individuals/Groups Providing Comments on Draft SEIS

Each commenter has been given a commenter identification number

Commenter Affiliation Commenter 

ID Number Comment Source

ADAMS 

Accession 

Number

Childs, Alan Prairie Island 

Indian Community 1 Transcript of Public Meeting ML093580120

Chezik, Michael U.S Department of 

Interior 2 Letter ML100830490

Doneen, Randal

Minnesota 

Department of 

Natural Resources

3 Letter ML100540516

Harlan, Thomas City of Red Wing 4 Letter ML100830514

Langdan, Matt

Minnesota 

Department of 

Natural Resources

5 Letter ML100540516

Mahowald, Philip Prairie Island 

Indian Community 6 Letter ML100830491

Parkyn, John None given 7 Letter ML100830492

Rosen, Diane

U.S. Department of 

Interior, Bureau of 

Indian Affairs

8 Letter ML100341193

Schimmel, Mark Northern States 

Power - Minnesota 9

Transcript of Public 

Meeting

Letter

ML093580120

ML100480966

Schweyen, Michael None given 10 Transcript of Public 

Meeting ML093580125

Tollefson, Kristen 

Eide None given 11 E-mail ML100840643

Westlake, Kenneth U.S. Environmental 

Protection Agency 12 Letter ML100570068

Winfrey, Victoria Prairie Island 

Indian Community 13 Transcript of Public 

Meeting ML093580120

Vaughn, Gail None given 14 E-mail ML100830492
Appendix A

A-165

Table 2 - Technical Issue Categories

All comments received on the draft SEIS were divided into one of the categories 

below, each of which has a unique abbreviation code.

Abbreviation 

Code Technical Issue Abbreviation Code Technical Issue

AR Aquatic Resources NO Noise

CI Cumulative Impacts NS Nuclear Safety

CR Cultural Resources OR Opposition to License 

Renewal

ED Editorial Changes to DSEIS OS Out of Scope

EJ Environmental Justice RW Radioactive Waste

EP

Emergency Planning –

Postulated Accidents SD Shutdown and 

Decommissioning

GW Ground Water SE Socioeconomics

HH Human Health SR Support of License 

Renewal/Nuclear Power

LR License Renewal Process TR Terrestrial Resources

MOU

Memorandum of Understanding 

with Prairie Island Indian 

Community
Appendix A

A-166

Commenter Number 1 – Alan Childs, Prairie Island Indian Community

The following pages contain the comments made by Alan Childs, Prairie Island Indian 

Community, during the afternoon session of the NRC public meetings held on 

December 17, 2009, on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-167

1-a-OR
Appendix A

A-168

1-b-GW

1-c-RW

1-d-RW
Appendix A

A-169

1-d-RW-Cont.

1-e-OR
Appendix A

A-170

COMMENTER 2 – Michael Chezik, U.S. Department of Interior

The following pages contain the written comments submitted by the U.S. Department of Interior 

on the Draft Supplemental Environmental Impact Statement for the Prairie Island Nuclear 

Generating Plant license renewal.
Appendix A

A-171

2-a-AR
Appendix A

A-172

2-a-AR

Cont.

2-c-AR

2-b-AR

2-d-AR
Appendix A

A-173

2-d-AR

Cont

2-e-AR

2-f-TR

2-g-TR
Appendix A

A-174
Appendix A

A-175

COMMENTER 3 – Randall Doneen, Minnesota Department of Natural Resources

The following pages contain the written comments submitted by the Minnesota Department of 

Natural Resources on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-176

3-b-LR

3-a-LR

3-c-AR
Appendix A

A-177

3-c-AR 

Cont.
Appendix A

A-178

3-c-AR 

Cont.

3-d-AR

3-e-TR

3-f-AR
Appendix A

A-179

3-f-AR 

Cont
Appendix A

A-180

Commenter Number 4 – Thomas Harlan, City of Red Wing, MN

The following pages contain the written comments submitted by Thomas Harlan, Attorney for 

the City of Red Wing, MN, on the Draft Supplemental Environmental Impact Statement for the 

Prairie Island Nuclear Generating Plant license renewal.
Appendix A

A-181

4-a-LR
Appendix A

A-182

4-b-EP 
Appendix A

A-183

4-b-EP 

Cont
Appendix A

A-184

4-c-GW

4-b-EP

Cont

4-e-SE

4-f-SE

4-d-GW
Appendix A

A-185

4-g-SE

4-f-SE 

Cont
Appendix A

A-186

4-g-SE 

cont
Appendix A

A-187

4-h-EP

4-g-SE

Cont
Appendix A

A-188

4-h-EP 

Cont
Appendix A

A-189

4-h-EP 

Cont

4-i-EJ

4-j-SE

4-k-SE

4-l-EP
Appendix A

A-190

Also submitted along with the written comments were three other documents which 

were determined to be Out of Scope (OS). The documents are:

1. Direct testimony of Marshall Hallock on behalf of the City of Red Wing, 

Minnesota before the Minnesota Public Utilities Commission, State of Minnesota. 

April 30, 2009. ADAMS Accession Number ML1008830511.

2. Surrebuttal of Marshall Hallock on behalf of the City of Red Wing, Minnesota 

before the Minnesota Public Utilities Commission, State of Minnesota. 

May 26, 2009. ADAMS Accession Number ML100830513.

3. City of Red Wing/Goodhue County Emergency Response Plan for the Prairie 

Island Nuclear Generating Plant. May 2007. 

ADAMS Accession Number ML100830512

4-l-EP

Cont

4-m-OS

4-n-OS

4-o-OS
Appendix A

A-191

COMMENTER 5 – Matt Langdon, Environmental Review Unit, Division of 

Ecological Resources, Minnesota Department of Natural Resources

The following pages contain the written comments submitted by the Minnesota Department of 

Natural Resources on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-192

5-a-AR

5-b-AR

5-c-TR
Appendix A

A-193
Appendix A

A-194

Commenter Number 6 – Philip Mahowald, Attorney for Prairie Island Indian 

Community

The following pages contain the written comments submitted by Philip Mahowald for the Prairie 

Island Indian Community on the Draft Supplemental Environmental Impact Statement for the 

Prairie Island Nuclear Generating Plant license renewal.
Appendix A

A-195

6-a-MOU
Appendix A

A-196

6-c-CR

6-a-MOU

Cont.

6-b-MOU
Appendix A

A-197

6-c-CR-Cont

6-d-HH

6-e-HH

6-f-AR

6-g-HH
Appendix A

A-198

6-h-RW

Cont

6-g-HH 

Cont

6-i-HH
Appendix A

A-199

6-i-HH

Cont

6-l-CR

6-k-CR

6-j-MOU
Appendix A

A-200

6-m-CR

6-n-CR

6-o-CR

6-p-EJ

6-q-EJ

6-r-EJ
Appendix A

A-201

6-r-EJ 

Cont

6-s-ED

6-t-AR
Appendix A

A-202

6-t-AR

Cont

6-u-TR

6-v-TR
Appendix A

A-203

6-v-TR

Cont
Appendix A

A-204

6-v-TR

Cont

6-w-GW

6-x-TR
Appendix A

A-205

6-z-GW

6-y-TR

Cont
Appendix A

A-206

6-aa-GW

Cont

6-ab-EJ

6-ac-EJ
Appendix A

A-207

6-ac-EJ

Cont

6-ad-GW

6-ae-GW
Appendix A

A-208

6-ae-GW

Cont

6-af-HH

6-ag-CR

6-ag-CR
Appendix A

A-209

6-ah-CR

6-ai-CI

6-aj-CR

6-ag-CR

Cont
Appendix A

A-210

6-ak-EJ

6-al-EJ

6-am-RW

6-an-CI
Appendix A

A-211

6-ap-CI

6-ao-ED

6-an-CI

Cont
Appendix A

A-212

6-ap-CI

Cont.

6-ar-RW

6-aq-RW
Appendix A

A-213

6-ar-RW

Cont

6-as-CR

6-at-EJ
Appendix A

A-214

6-at-EJ

Cont

6-au-EJ

6-av-RW
Appendix A

A-215

6-aw-EP
Appendix A

A-216

6-ba-AR

6-az-HH

6-bc-RW

6-ay-LR

6-bb-MOU

6-bd-OS

6-ax-LR
Appendix A

A-217
Appendix A

A-218

COMMENTER 7 – John Parkyn, No affiliation given.

The following page contains the comments submitted by e-mail from John Parkyn on the 

Supplemental Environmental Impact Statement for the Prairie Island Nuclear Generating Plant 

license renewal.
Appendix A

A-219

From: John D Parkyn [jdp@dairynet.com]

Sent: Wednesday, December 30, 2009 2:15 PM

To: Keegan, Elaine

Subject: Comments on Draft Environmental Report for Prairie Island 

Nuclear Plant 

License renewal

I am writing to comment on the draft environmental report for the Prairie 

Nuclear Plant license renewal. I support the unit life extension as it 

minimizes pollution significantly. As both a user of the plants' output 

and a down river valley neighbor, I know that the alternatives are 

limited.

The No Action alternative will shut the plant down and cause generation by 

fossil fuels to increase (that's what we use in the Midwest). It will 

thus add to air emissions regardless of the use of coal or natural gas. 

The renewable sources are intermittent and very expensive. As a former 

County Board member I can assure our low income farming county can not 

stand many more rate increases in energy costs. We are not able in the 

MN- WI area to offset PI by either "conservation" or "renewable, thus it 

is imperative for us that the facility continues to operate. Our hope is 

to reduce emissions by the use of conservation and renewal energy, using 

that up to replace the non-emitting Prairie Island will be a major step 

backward in air quality efforts.

The environmental analysis for an alternative to PI must come up with 

higher total impact on society.

If you have any questions, please contact me at (608) 788-7004.

John Parkyn

W636 Cherry St.

Stoddard, WI 54658

7-a-SR
Appendix A

A-220

Commenter Number 8 – Diane Rosen, Bureau of Indian Affairs, U.S. Department 

of Interior

The following pages contain the written comments submitted by the Bureau of Indian Affairs, 

U.S. Department of Interior on the Draft Supplemental Environmental Impact Statement for the 

Prairie Island Nuclear Generating Plant license renewal.
Appendix A

A-221

8-c-CR

8-e-ED

8-d-CR

8-a-ED

8-f-CR

8-b-C
Appendix A

A-222

8-i-ED

8-k-CR

8-j-CR

8-g-CR

8-h-CR
Appendix A

A-223

Commenter Number 9 – Mark Schimmel, Site Vice President,

Prairie Island Nuclear Generating Plant

The following pages contain the comments made by Mark Schimmel, Prairie Island Nuclear 

Generating Plant, during the afternoon session of the NRC public meetings held on 

December 17, 2009, on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-224
Appendix A

A-225

9-a-SR
Appendix A

A-226
Appendix A

A-227

Commenter Number 9 – Mark Schimmel, Site Vice President,

Prairie Island Nuclear Generating Plant (Cont.)

The following pages contain the written comments submitted by Mark Schimmel, Prairie Island 

Nuclear Generating Plant on the Draft Supplemental Environmental Impact Statement for the 

Prairie Island Nuclear Generating Plant license renewal.
Appendix A

A-228

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

1 ii Replace "Dakota" with "Goodhue" 9-b-ED

2 iii Should be "States" 9-c-ED

3 iii Should be "licenses" 9-d-ED

4 iii Should be "from a new" 9-e-ED

5 iii Replace "combination cycle" with "combined cycle plant" 9-f-ED

6 iii Should be "licenses" 9-g-ED

7 v Indent to the right 9-h-ED

8 vii Correct capitalization 9-i-ED

9 xiii Add “the” before Prairie Island 9-j-ED

10 xiii “States” should not be capitalized 9-k-ED

11 xiii Should read "Volumes 1 and 2". 9-l-ED

12 xiii "supplemental environmental impact statement" should 

be capitalized

9-m-ED

13 xiii "environmental report" should be capitalized 9-n-ED

14 xiii Change "requesting a renewed" to "requesting renewed" 9-o-ED

15 xiii Add “Units” after PINGP 9-p-ED

16 xiii Change to "licenses" 9-q-ED

17 xiii Separate "decisionmakers" into two words throughout 

the DSEIS

9-r-ED

18 xiii Change "license is issued" to "licenses are issued" 9-s-ED

19 xiii Change "license is not" to "licenses are not" 9-t-ED

20 xiv "MIssissippi" should be “Mississippi” (capitalization) 9-u-ED

21 xix Delete "is" and capitalize. Should read "As Low As 

Reasonably Achievable"

9-v-ED

22 xx Change "mSy" to "mSv" 9-w-ED

23 xxi Add "man" after equivalent 9-x-ED

24 xv

Delete this discussion. The subject is also discussed in 

lines 30 through 33, and this is not consistent with the 

discussion in lines 30 through 33. The related 

discussion on pages 3-4 and 3-5 makes no reference to 

the need for consultation.

9-y-ED

25 xv

Delete "nuclear" from line 17 on page xv. The 

transporter to be used will not be specific to nuclear 

component transport.

9-z-ED

26 xv

Revise "via barge, though no changes to the river" to "by 

barge via river system, no changes to rivers..."

9-aa-ED
Appendix A

A-229

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

27 xv

Impact of refurbishment on human health is not 

discussed in the DSEIS Section 3.0 because it is a 

Category 1 issue, and, therefore, the discussion in lines 

39 through 44 on page xv should be deleted.

9-ab-ED

28 xvi

"approximately 80 days" should be used for the duration 

of the steam generator replacement outage throughout 

the DSEIS.

9-ac-ED

29 xvi Change “cultural resources management plans” to “a 

Cultural Resource Management Plan”

9-ad-ED

30 xvi, etc.

General comment: search document for instances where 

the acronym for Northern States Power (NSP) is 

erroneously written as “NPS.” Please define “NSP” as 

“Northern States Power Company - Minnesota” in line 51 

on page xx.

9-ae-ED

31 xvii Should be "units" 9-af-ED

32 xviii Give the table on page xviii a number, and a title that 

clarifies the purpose of the table.

9-ag-ED

33 1-2 Change black background to white so the text and lines 

in the shaded area can be read.

9-ah-ED

34 1-2 "January" should be "April." The LRA was submitted in 

April, not January.

9-ai-ED

35 1-2 Delete "(NMC 2008b)" or add the reference information 

to Section 1.10 of the DSEIS.

9-aj-ED

36 1-5 "scoping" should be "comment" 9-ak-ED

37 1-5, etc.

General comment: search entire document for instances 

when “PINGP” is erroneously written as “PINPG" or 

“PINPGP”.

9-al-ED

38 1-6 "(PIIC 2008)" does not have a reference in Section 1.10 

of the DSEIS.

9-am-ED

39 1-8 General=s should be "General's." This is an issue 

throughout the DSEIS and should be globally corrected.

9-an-ED

40 1-11

MN DNR-Fish, mussel, and icthyoplankton collection 

permit: Replace "14658" with "15975" and replace 

"14657" with "15994"

MPCA - Operation of oil-fired boiler and diesel ... Permit: 

Replace "04900030-003" with "04900030-004" 

State of Tennessee - Transportation of radioactive 

materials ... Permit: Replace “T-MN003-L08” with “TMN003-10”

WDNR - Collect Fish and ichthyoplankton .... monitoring: 

Replace “SCP-WCR-20-C-08” with “SCP-WCR-20-C-10” 

9-ao-ED
Appendix A

A-230

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

41 1-12

Remove South Carolina radwaste permit. Permit was 

not renewed for 2009 as the Barnwell facility is closed to 

PINGP.

9-ap-ED

42 2-1

The PINGP cooling towers are not natural draft cooling 

towers. They are induced mechanical draft cooling 

towers, and they are not the most conspicuous 

structures on the site.

9-aq-ED

43 2-1

By the end of 2009 there were 25 casks in the PINGP 

ISFSI, and the 26th cask will be loaded and moved to 

the ISFSI in the first quarter of 2010. The NSP 2008 

reference is no longer accurate with respect to the 

number of casks in the PINGP ISFSI.

9-ar-ED

44 2-1

There are 40 fuel assemblies in each cask. Adjust the 

number of fuel assemblies as required to reflect the 

number of casks noted at the beginning of line 29. 

Based on the 26 casks currently loaded, the number of 

fuel assemblies in the ISFSI is 1,040.

9-as-ED

45 2-1 Replace "operating" with "operation" 9-at-ED

46 2-2

This statement is incorrect for the PINGP steam 

generators. It should read "that produces steam." The 

statement is describing B&W once-through steam 

generators, not Westinghouse/Areva recirculating Utube steam generators.

9-au-ED

47 2-2 Replace "from" with "through" 9-av-ED

48 2-2 "(NRC 1990)" does not have a reference in Section 1.10 

of the DSEIS.

9-aw-ED

49 2-2

The discussion of the primary containment in Lines 10 

through 13 on page 2-2 is not accurate for PINGP. In its 

place, use the discussion of the PINGP containment 

from the last paragraph on page 3-2 of the PINGP 

Environmental Report. The term reactor building is not 

used at PINGP. 

9-ax-ED

50 2-2 Delete "in the reactor building." The spent fuel pool is 

not in the reactor building at PINGP.

9-ay-ED

51 2-3 The PI report is titled “Radiological Environmental 

Monitoring Report” instead of “Operating” report.

9-az-ED

52 2-3

The discussion from Section 2.1.2.1 continues on page 

2-6 with a large gap on page 2-3. Suggest that more of 

the discussion for section 2.1.2.1 be included on page 2-

3. Figures 2-1 and 2-2 should be placed immediately 

following page 2-1 where they are first referenced. 

9-ba-ED

53 2-4, 2-5, 

2-13

General comment: The quality of the figures in the 

DSEIS is poor, making them difficult to read. 

9-bb-ED
Appendix A

A-231

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

54 2-6

Replace "during" with "prior to". Replacement of the 

PINGP Unit 2 steam generators is scheduled for 2013, 

which is prior to the period of extended operation (PEO)

for Unit 2.

9-bc-ED

55 2-6

Delete "from PINGP 1 and 2 during the period of 

extended operations." from lines 47 through 48 since the 

steam generator replacement outage is planned to be 

completed prior to the PEO for Unit 2. Since this 

paragraph is related to refurbishment, it should be 

relocated to Section 3 of the DSEIS.

9-bd-ED

56 2-6 Should be "Unit 1" not "Unit 2." 9-be-ED

57 2-7 Replace "resulted" with "results." 9-bf-ED

58 2-7 Should read "reactor coolant hydrogen stripping" (Ref: 

USAR 9.3.2).

9-bg-ED

59 2-7 Replace "increase or decrease" with "change 

significantly."

9-bh-ED

60 2-7

Replace "during" with "prior to". Replacement of the 

PINGP Unit 2 steam generators is scheduled for 2013, 

which is prior to the PEO for Unit 2.

9-bi-ED

61 2-7

Delete "from PINGP 1 and 2 during the period of 

extended operations" from lines 36 through 45 since the 

steam generator replacement outage is planned to be 

completed prior to the PEO for Unit 2. Since this 

paragraph is related to refurbishment, it should be 

relocated to Section 3 of the DSEIS.

9-bj-ED

62 2-7 Should be "Unit 1" not "Unit 2" 9-bk-ED

63 2-8 Revise to read "does not normally produce low-level ..." 9-bl-ED

64 2-8

Delete "evaporator bottoms, and." The radioactive 

waste evaporator system is no longer used at PINGP. 

The equipment is abandoned in place. 

9-bm-ED

65 2-8

Delete “solidification of the waste with an in-drum 

cement system.” The in-drum cement system is no 

longer used at PINGP. The equipment is abandoned in 

place.

9-bn-ED

66 2-8 Delete “compacted” and replace with “collected”. 

Compaction is no longer used at PINGP.

9-bo-ED

67 2-6

2-8

"(NMC 2001)" does not have a reference in Section 2.4

of the DSEIS. 

9-bp-ED

68 2-8

Replace "during" with "prior to." Replacement of the 

PINGP Unit 2 steam generators is scheduled for 2013, 

which is prior to the PEO for Unit 2.

9-bq-ED
Appendix A

A-232

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

69 2-8

Delete "from PINGP 1 and 2 during the period of 

extended operations." from line 37 since the steam 

generator replacement outage is planned to be 

completed prior to the PEO for Unit 2. Since this 

paragraph is related to refurbishment, it should be 

relocated to Section 3 of the DSEIS.

9-br-ED

70 2-9 Should read, “PINGP 1 and 2 is classified as a Small 

Quantity Generator.”

9-bs-ED

71 2-9 Should read, "PINGP 1 and 2 is subject to ..." 9-bt-ED

72 2-10 Replace “seven” with “eight”. There are now eight onsite 

septic systems at PINGP.

9-bu-ED

73 2-10 Verify reference "(NMC 2008)" is the proper reference. 9-bv-ED

74 2-10 PINGP does engage in recycling of consumables. 

Replace "do not" with "does".

9-bw-ED

75 2-10 Verify reference "(EPA 2008b)" is the proper reference. 

The EPA references are confusing in Section 2.4.

9-bx-ED

76 2-12 Replace "pesticides" with "herbicides". 9-by-ED

77 2-15 Sentence should begin “River water used for cooling...” 9-bz-ED

78 2-15 "(NRC 1973)" does not have a reference in Section 2.4 

of the DSEIS.

9-ca-ED

79 2-16 Should have “the” in front of "discharge". 9-cb-ED

80 2-16

Prior to this, presented as "xx fps (xx m/s)", then 

switched to "xx m/s (xx fps)". Use consistent units of 

measure: fps (m/s). This should be addressed globally 

through the DSEIS.

9-cc-ED

81 2-18

The cooling towers are induced mechanical draft cross 

flow towers. Replace "Fans blow air up through the 

falling water" with "Fans draw air up through the streams 

of water." (Ref: USAR 11.6.2)

9-cd-ED

82 2-18

Sentence should clarify that NPDES covers process 

water effluent. The sentence currently does not make a 

distinction as to what type of effluent is regulated under 

the permit. Replace "effluent" with "cooling water".

9-ce-ED

83 2-22 Reword to read "...order to prevent condenser inlet 

temperatures from exceeding..."

9-cf-ED

84 2-22 Temperature monitoring locations should be SW not SD. 9-cg-ED

85 2-22 Delete "directly" from line 13. The monitors are on the 

lock and dam piers/columns.

9-ch-ED

86 2-22 Replace "service" with "cooling". 9-ci-ED
Appendix A

A-233

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

87 2-24

Delete sentence beginning with "In 2009, ..." in lines 9 

through 11, and replace with the following to update the 

dredging status: “In 2009, PINGP 1 and 2 performed 

dredging of a 0.9 acre area of the intake channel and 

within the intake screenhouse. In 2010, PINGP 1 and 2 

plans to perform a larger-scale maintenance dredging 

project of the intake channel."

9-cj-ED

88 2-24 Remove "will be implemented" from line 12. 9-ck-ED

89 2-24 Add "and modified by plant construction activities" after 

"were disturbed".

9-cl-ED

90 2-25 Add the centimeter equivalent after "40 in." 9-cm-ED

91 2-25 "(NCDC 2006)" does not have a reference in Section 2.4 

of the DSEIS.

9-cn-ED

92 2-26 Delete "by the site meteorologist". PINGP does not 

have a site meteorologist.

9-co-ED

93 2-26 Insert "for" after (NAAQS). 9-cp-ED

94 2-26

Replace lines 29 through 34 with the following, "PINGP 

1 and 2 has a number of stationary emission sources, 

which include eight standby emergency power supply 

diesel engines, two diesel engine-powered cooling water 

pumps, and three emergency operations diesel engines, 

all of which are required for safe start-up and continuous 

operation. The facility currently has a Title V operating 

permit that allows the installation and operation of these 

emission units. The facility is considered a synthetic 

minor source for New Source Review (NSR) purposes, 

due to the low quantity of emissions and the restrictions 

on operation of its stationary sources."

9-cq-ED

95 2-27

"(NMC 2001g)" is not listed as a reference in Section 2.4 

of the DSEIS. The correct reference may be (NMC 

2001q). 

9-cr-ED

96 2-28

Replace "liquid discharge" with "liquid radioactive waste 

discharge" in both locations in line 10. Insert "monitored 

and" between "were" and "released". 

9-cs-ED

97 2-28 “Radiation” should be “Radiological.” 9-ct-ED

98 2-28

The statement that PINGP does not currently implement 

a general Ground Water Monitoring Program is not 

correct. PINGP has implemented a Groundwater 

Monitoring Program per the NEI Ground Water 

Protection Initiative guidelines. Sample results from this 

program are reported in the annual REMP report. 

Aspects of this program are discussed in Lines 7 

through 26 on page 4-19 of the DSEIS. 

9-cu-ED
Appendix A

A-234

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

99 2-29

"(MPCA 2008)" is not listed as a reference in Section 2.4 

of the DSEIS. The correct reference may be (MPCA 

2008k).

9-cv-ED

100 2-29 Replace "2-4 and 2-5" with "2-9 and 2-10." 9-cw-ED

101 2-29 Remove "Month (cfs)" from the middle of Table 2-9. 9-cx-ED

102 2-30 Delete "...main stem of the." 9-cy-ED

103 2-30

General comment: Check consistency of references to 

the distance from PINGP to Lock and Dam 3. The 

distance specified in the PINGP Environmental Report 

(Sections 2.2.1 and 2.3.1.2) is approximately one mile. 

9-cz-ED

104 2-30

Section 2.1.5 discusses five transmission lines in scope 

of license renewal; this section states there are three 

transmission lines in scope.

9-da-ED

105 2-31 "(Benson 2008)" is not listed as a reference in Section 

2.4 of the DSEIS.

9-db-ED

106 2-32 Replace "3169(a)" with "316(a)". 9-dc-ED

107 2-32 Replace "CWA" with "Clean Water Act (CWA)." 9-dd-ED

108 2-34 Common buckthorn is also present on the PINGP site. 9-de-ED

109 2-35 Replace "lists" with "list". 9-df-ED

110 2-35

The headings of tables 2-11 and 2-12 do not match this 

text description. Clarify the titles of Tables 2-11 and 2-

12 to match the descriptions on lines 26 through 30, to 

provide a more accurate description of the table content. 

Also add "species of concern" to the text description in 

lines 26 through 30. 

9-dg-ED

111 2-36 Replace "muscles" with "mussels". 9-dh-ED

112 2-36 Replace "zebra populations" with "zebra mussel 

populations".

9-di-ED

113 2-37 Change “sties” to “sites”. 9-dj-ED

114 2-37 This section should acknowledge that the Winged 

Mapleleaf is a species of mussel.

9-dk- ED

115 2-37 (WDNR 2008) is not listed as a reference in Section 2.4 

of the DSEIS.

9-dl-ED

116 2-40 Sentence should begin, “The PINGP Unit 1 containment 

building has a nest box...”

9-dm-ED

117 2-41 Replace "prescent" with "present." 9-dn-ED

118 2-45 Remove Figure 2-2 from page 2-45, it is originally shown 

on page 2-5.

9-do-ED

119 2-46 There is no Section 2.2.8.1. 9-dp-ED

120 2-46 "Table 2.14" should be "Table 2-14." 9-dq-ED
Appendix A

A-235

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

121 2-47

Delete the word "County" after "Goodhue", it is not 

necessary. Also add "and the Region" to the end of the 

title.

9-dr-ED

122 2-47 "Table 2.15" should be "Table 2-15". 9-ds-ED

123 2-48

The reference to the Mt. Simon-Hinkley aquifer in lines 9 

and 10 appears to be incorrect. The 180 ft depth listed 

is inconsistent with the 500 ft depth listed in line 7 of 

page 2-48. 

9-dt-ED

124 2-49 (EPA 2008) is not listed as a reference in Section 2.4 of 

the DSEIS.

9-du-ED

125 2-50

This statement is no longer accurate. Wakonade drive 

is now two way to PINGP. As such, delete "..., which is 

currently limited to north-bound out-going traffic from the 

PINGP 1 and 2 site."

9-dv-ED

126 2-55 "Table 2.17" should be "Table 2-17." 9-dw-ED

127 2-56 "Table 2.19" should be "Table 2-19" and "Table 2.20" 

should be "Table 2-20."

9-dx-ED

128 2-56 "Table 2.19" should be "Table 2-19." 9-dy-ED

129 2-58 "Table 2.20" should be "Table 2-20." 9-dz-ED

130 2-59 "Table 2.21" should be "Table 2-21." 9-ea-ED

131 2-61 "Table 2.22" should be "Table 2-22." 9-eb-ED

132 2-61 "Table 2.23" should be "Table 2-23." 9-ec-ED

133 2-62 This statement should note that the indented information 

is not a direct quote from the NSPM ER.

9-ed-ED

134 2-63 (AMC 2002) is not listed as a reference in Section 2.4 of 

the DSEIS.

9-ee-ED

135 2-63 (Hove 2006) is not listed as a reference in Section 2.4 of 

the DSEIS.

9-ef-ED

136 2-63 References to "Table 2.24" should be changed to "Table 

2-24."

9-eg-ED

137 2-63 (Fredrikson & Byron 2001) is not listed as a reference in 

Section 2.4 of the DSEIS.

9-eh-ED

138 2-65 Since issuance of the FES, underbrush and woods have 

taken over most of the grassland.

9-ei-ED

139 2-65 The citation to (Hildebrandt 2008) should be (Dobbs 

1988).

9-ej-CR

140 2-65

Woodland culture is defined by production of pottery and 

earthen mound construction, though there is evidence 

that these technologies were present in earlier periods

9-ek-CR

141 2-66 Replace "the Woodland period" with "the earlier 

Woodland period."

9-el-CR
Appendix A

A-236

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

142 2-66 The citation to (Hildebrandt 2008) should be (Dobbs 

1988).

9-em-CR

143 2-66 Replace “follow” with “follow and may have existed 

concurrently with.”

9-en-CR

144 2-66

The Bartron Village site has Late Woodland and Oneota 

components, and a very small amount of Mississippianrelated artifacts.

9-eo-CR

145 2-66

The sentence about neighborhoods and cultural lines 

needs to be modified. This has never been tested at the 

Bartron site, although several researchers have 

suggested it.

9-ep-CR

146 2-66

Take out the sentence about Bartron and the Middle 

Mississippian characteristics. This has been disproven 

over the years since Gibbon (1979) and others 

suggested its connections.

9-eq-CR

147 2-66

Replace "Oneota peoples can be traced through the 

years to ancestral" with "Oneota peoples are among 

some of the antecedents to ancestral..."

9-er-CR

148 2-66

The citation should be the letter Ron Schirmer and Emily 

Hildebrant wrote on July 4, 2008 to update the PIIC and 

PINGP on the fieldwork conducted at the Bartron Site.

9-es-CR

149 2-66 Replace "Middle Mississippian" with "Middle 

Mississippian-related."

9-et-CR

150 2-67 Replace “discovered” with "recorded." 9-eu-CR

151 2-67 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-ev-CR

152 2-67 Insert "Christian" in front of "church." 9-ew-CR

153 2-67 (MHS 2009) is not listed as a reference in Section 2.4 of 

the DSEIS.

9-ex-CR

154 2-67 The tribe that the tribal elder belongs to should be 

identified.

9-ey-CR

155 2-67 Replace "most the land" with "most of the land." 9-ez-CR

156 2-67

Delete sentence "Members of the PIIC 

have......generations." The heritage of the PIIC on 

Prairie Island is stated more clearly in the ending 

sentence of the paragraph (lines 41 through 44).

9-fa-CR

157 2-67

What is the reference for the statement that the 

Mdewakanton Dakota are descendants of the “earliest 

known inhabitants?” 

9-fb-CR

158 2-68 Replace "1034" with "1934." 9-fc-ED
Appendix A

A-237

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

159 2-69

Reference (Hildebrant Iffert 2010) documents 13 

archaeological sites, 11 reported sites and 2 unrecorded 

but reported sites. See comments on Table 2-25 for a 

summary of the 13 sites.

9-fd-CR

160 2-69 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-fe-CR

161 2-69 Wilford only excavated at the Bartron Site, not the Birch 

Lake Mound Group.

9-ff-CR

162 2-69 Insert after "mounds", "at least seven and possibly 10 

mounds may have been on the PINGP site property."

9-fg-CR

163 2-69

Johnson identified 21GD148 in 1980, not in the 1960s. 

This sentence is probably referring to 21GD181, The 

Pickerel Slough Site.

9-fh-CR

164 2-69 End sentence at "uncovered". Delete remaining 

information. 

9-fi-CR

165 2-69 -

2-70

Based on reference (Hildebrant Iffert 2010), revise Table 

2-25 as shown in Enclosure 2.

9-fj-CR

166 2-70 Replace first sentence with: "The PINGP 1 and 2 cooling 

towers are laid out in a roughly east-west configuration." 

9-fk-ED

167 2-70 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-fl-CR

168 2-71 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-fm-CR

169 2-71 NSPM is not aware of any archaeological work 

performed in 2005.

9-fn-CR

170 2-71 Add "and no cultural findings" after "no artifacts 

recovered."

9-fo-CR

171 2-71 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-fp-CR

172 2-76 The citation to (Hildebrandt, Emily 2008) should be 

(Hildebrant Iffert 2010).

9-fq-CR

173 3-1 Add new category under "Land Use": "Offsite Land Use". 

This is a Category 2 issue. 

9-fr-ED

174 3-2 Northern “States” Power 9-fs-ED

175 3-2

Delete "with new, once-through, enhanced steam 

generators." PINGP does not use once-through steam 

generators. The original and new steam generators are 

"recirculating U-tube vertical steam generators." 

9-ft-ED

176 3-2 Delete everything after "delivered", and replace with 

"and installed in 2013."

9-fu-ED

177 3-2 "(AREVA 2008)" is not listed as a reference in Section 

3.5 of the DSEIS. 

9-fv-ED
Appendix A

A-238

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

178 3-2

Reword the sentence on lines 15 and 16 of page 3-2 to 

read: "The replacement steam generators will be 

transported across the Atlantic Ocean via ship, and then 

transferred to a barge for transportation via river 

system."

9-fw-ED

179 3-3

Revise “...temporary buildings will be constructed, 

including...” with “...temporary buildings will be 

constructed, which may include...”. Temporary buildings 

will be required to support Unit 2 steam generator 

replacement; however, specific plans for temporary 

buildings are still under development. 

9-fx-ED

180 3-3

Replace “Warehouses will be built...” with “Warehouses 

may be built...” in line 3. Replace “will” with “if built, 

would” in line 4. Specific plans for buildings required to

support steam generator replacement are under 

development. NSPM may determine that no additional 

warehouses are required to support Unit 2 steam 

generator replacement.

9-fy-ED

181 3-3 Delete "via rail car". Other modes of transport could be 

utilized.

9-fz-ED

182 3-3

Replace “Temporary construction would...” with 

“Temporary construction may...”. Temporary buildings 

will be required to support Unit 2 steam generator 

replacement; however, specific plans for temporary 

buildings are still under development.

9-ga-ED

183 3-3 Insert "offsite" between "no" and "road." 9-gb-ED

184 3-4 Insert "offsite" between "no" and "overland." 9-gc-ED

185 3-4

Lines 18 through 22 state that the falcon nest on Unit 1

is far enough away from the ground so that steam 

generator replacement is not expected to cause 

significant noise or other types of disturbance to the 

birds. Based on that conclusion, and the distance 

between the nest box on Unit 1 and the Unit 2 steam 

generator replacement activities, we suggest that the 

mitigation measure to limit activities during midday hours 

be deleted. 

9-gd-ED

186 3-4

Lines 22 through 24 note that the steam generator 

replacement will occur outside the falcon breeding 

period. Since the replacement is already planned to 

occur outside the breeding period, we suggest that the 

mitigation measure be deleted. 

9-ge-ED
Appendix A

A-239

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

187 3-5

The mitigation measure noted in lines 2 through 5 on 

page 3-5 related to protection of the Higgins Eye 

relocation project is unnecessary. The barge landing 

site to be used during receipt of the replacement steam 

generators is located near the plant intake screen house 

and is located well down river of the Higgins Eye 

relocation project. Because there would be no reason 

for the replacement steam generator barge to travel up 

river beyond the location of the barge landing site, we 

suggest that the mitigation measure be deleted. 

9-gf-AR

188 3-5 Replace "PINGP 1 and 2, Unit 1" with “PINGP Unit 1...” 9-gg-ED

189 3-6

Lines 22 through 24 on page 3-6 discuss mitigation 

measures that could be taken to mitigate potential air 

quality impacts related to the steam generator 

replacement project. In a December 24, 2009 response 

to new PIIC environmental contentions, NSPM 

committed to work with the PIIC to coordinate and 

implement appropriate measures to mitigate 

transportation impacts resulting from the Unit 2 steam 

generator replacement project, including (1) using 

NSPM's private access road for heavy truck traffic 

related to the project, so that it minimizes interference 

with traffic entering the PIIC casino and reservation 

property; (2) using local law enforcement to control 

traffic during PINGP shift changes; and (3) staggering 

the refurbishment work schedule if necessary. These 

lines should be revised to reflect the NSPM response to 

the PIIC contention.

9-gh-ED

190 3-8

Lines 14 through 19 on page 3-8 discuss mitigation 

measures that could be taken to mitigate potential 

transportation impacts related to the steam generator 

replacement project. In a December 24, 2009 response 

to new PIIC environmental contentions, NSPM 

committed to work with the PIIC to coordinate and 

implement appropriate measures to mitigate 

transportation impacts resulting from the Unit 2 steam 

generator replacement project, including (1) using 

NSPM's private access road for heavy truck traffic 

related to the project, so that it minimizes interference 

with traffic entering the PIIC casino and reservation 

property; (2) using local law enforcement to control 

traffic during PINGP shift changes; and (3) staggering 

the refurbishment work schedule if necessary. These 

lines should be revised to reflect the NSPM response to 

the PIIC contention.

9-gi-NO
Appendix A

A-240

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

191 3-8 Offsite Land Use is not listed as a Category 2 issue in 

table 3-1 (it is not mentioned at all).

9-gj-ED

192 3-8 This section deals with refurbishment impacts, so this 

paragraph does not belong in this section.

9-gk-ED

193 3-8

Replace last three sentences with, "NSP has no plans to 

alter historic and archaeological resources at the PINGP 

1 and 2 site for license renewal. Should activities 

involve areas that are considered undisturbed or having 

a significant potential for impacting resources, then 

further consultation with the SHPO, MN State 

Archaeologist, and PIIC will be initiated in accordance 

with corporate procedures."

9-gl-CR

194 3-9 This paragraph should be moved to just prior to the 

conclusion paragraph for this Section. 

9-gm-ED

195 3-9

Revise “Several temporary buildings would be built, 

including...” with “Several temporary buildings would be 

built, which may include...”. Temporary buildings will be 

required to support Unit 2 steam generator replacement; 

however, specific plans for temporary buildings are still 

under development.

9-gn-ED

196 3-9

Replace “Warehouse(s) would also be built...” with 

“Warehouse(s) may be built...” in line 16. Replace 

“would” with “if built, would” in line 18. Specific plans for 

buildings required to support steam generator 

replacement are under development. NSPM may 

determine that no additional warehouses are required to 

support Unit 2 steam generator replacement.

Delete “to temporarily house the replaced steam 

generators” from line 17. Warehouses will not be used 

to temporarily house the replaced steam generators. 

9-go-ED

197 3-9 Insert "offsite" between "no" and "road." 9-gp-ED

198 3-9

Delete "nuclear" from line 20 on page 3-9. The 

transporter to be used will not be specific to nuclear 

component transport.

9-gq-ED

199 3-9 Replace "PINGP 1 and 2, Unit 2" with “PINGP Unit 2...” 9-gr-ED

200 3-9

Insert the following sentence into line 23: "The service 

road was used during the Unit 1 steam generator 

replacement."

9-gs-ED

201 3-9

Permits and approvals will not be required because 

transport of the replacement steam generators will not 

occur on public roads. As such, delete the sentence that 

begins with "According to NSP..." in lines 24 and 25.

9-gt-ED

202 3-9 Replace "PINGP 1 and 2, Unit 2" with “PINGP Unit 2...” 9-gu-ED
Appendix A

A-241

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

203 3-9 Replace "generator" with "generators." 9-gv-ED

204 3-9

Replace "with the NRC, MHNS, and the PIIC" with 

"through consultation with applicable agencies in 

accordance with corporate procedures." 

9-gw-CR

205 3-9 Environmental justice is not a Category 2 issue per table 

3-1. It is “Uncategorized.”

9-gx-ED

206 3-10

For the nine Category 2 issues and environmental 

justice, the impacts of refurbishment at PINGP 1 and 2 

range from no impact to MODERATE impact. There 

would be no impact for the following refurbishment 

issues: Housing, Public Services - Education, Public 

Services - Public Utilities, and Offsite Land Use. There 

would be SMALL impact for the following refurbishment 

issues: Terrestrial Resources, Threatened and 

Endangered Species - Terrestrial, Threatened and 

Endangered Species - Aquatic, Air Quality, and Historic 

and Archaeological Resources. There would be a 

SMALL to MODERATE impact for the following 

refurbishment issues: Public Service - Transportation, 

and Environmental Justice.

9-gy-ED

207 4-2 DSEIS previously referred to aquifer as the “Mount 

Simon-Hinckley” aquifer.

9-gz-ED

208 4-12 Replace "Sander" with "Stizostedion." 9-ha-ED

209 4-14 Xcel Energy's APP for Wisconsin has been approved, 

and is being implemented. 

9-hb-ED

210 4-14 Replace "February" with "January." 9-hc-ED

211 4-14

In April 2008, NSPM personnel found a dead Pelican off 

of NSPM property, but near the Spring Creek 

transmission lines south of the PINGP Training Center. 

9-hd-TR

212 4-15 Table 4-10 should follow this paragraph for consistency. 9-he-ED

213 4-15

Reference to Appendix E is incorrect. The biological 

assessment is included in Appendix D. Suggest that the 

biological assessment be separated into a new 

Appendix E, and the existing Appendices E and F be 

renumbered. 

9-hf-ED

214 4-16

It is important to note that the accuracy of the 1984 data 

for impingement of all fish species is in question due to 

sampling methodology.

9-hg-ED

215 4-17 Add period to end of sentence. 9-hh-ED

216 4-19 Replace "Operating" with "Monitoring." 9-hi-ED

217 4-19 Note that the practice of discharging to the landlocked 

area was discontinued in 2009. 

9-hj-ED
Appendix A

A-242

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

218 4-21

What is the basis for the statement that the planned 

refurbishment activities will result in slightly higher dose 

to the public? Suggest deletion of lines 1 through 7. 

The discussion of dose to the public resulting from 

refurbishment activities is not appropriate for Section 4. 

Radiation exposure to the public during refurbishment is 

a category 1 issue (NUREG-1555, Supplement 1, page 

3.0-3). In addition, Section 4 discusses potential 

environmental impacts related to the period of extended 

operation. The Unit 2 steam generator replacement will 

be completed prior to the period of extended operation

for Unit 2. 

9-hk-HR

219 4-24

Delete lines 7 through 15, because, as stated in lines 6 

and 7, the potential impacts from electric shock would be 

small, and because the NRC did not identify any cost 

benefit to the mitigation measures proposed. 

Furthermore, no trespassing signs are already in place 

to restrict access to those NSPM transmission lines near 

the PIIC. Erecting barriers along the remaining 

transmission lines in scope of license renewal or raising 

the lines is not practical or cost effective and is not 

warranted where, as here, compliance with the NESC 

standards has been demonstrated.

9-hl-HR

220 4-25 Final category should be “Uncategorized” 9-hm-ED

221 4-28

The statements that the assessed value of PINGP 1 and 

2 is not expected to increase are not correct. The value 

of PINGP will increase as a result of the replacement of 

the Unit 2 steam generators. These statements are not 

consistent with the information provided on page 2-29 of 

the PINGP ER. 

9-hn-SE

222 4-29 "(MNHS 2008)" is not listed as a reference in Section 

4.12 of the DSEIS. 

9-ho-ED

223 4-29 "(PIIC 2008a)" is not listed as a reference in Section 

4.12 of the DSEIS. 

9-hp-CR

224 4-29 "(PIIC 2008c)" is not listed as a reference in Section 

4.12 of the DSEIS. 

9-hq-CR

225 4-30 The Birch Lake Mound Group has not been dated to the 

Mississippian period.

9-hr-CR

226 4-30 "(Johnson, Peterson, and Streiff 1969)" is not listed as a 

reference in Section 4.12 of the DSEIS. 

9-hs-CR

227 4-30 Change last sentence to read "Portions of these sites 

could still be intact and should be avoided."

9-ht-CR

228 4-31 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-hu-CR
Appendix A

A-243

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

229 4-31

Revise the last sentence to read, "A Phase 1 

Reconnaissance Field Study conducted by NSP in 2009 

did not find any evidence of these reported mounds."

9-hv-CR

230 4-31 The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010).

9-hw-CR

231 4-31 Insert "may be" after "remains." 9-hx-CR

232 4-32 Add "(Hildebrant Iffert 2010)" at end of sentence. 9-hy-CR

233 4-32

Delete "Subsequent to the issuance of this draft SEIS." 

This statement is not accurate, and will not be required 

in the final SEIS.

9-hz-ED

234 4-32 NSPM has conducted the Phase I survey and the tense 

of this paragraph should be updated to reflect that.

9-ia-CR

235 4-32

Delete the sentence discussing construction of 

warehouses from line 37, the original steam generators 

removed from Unit 2 will not be permanently stored 

onsite. Delete the sentences starting with “All 

construction will take place...” and “Undisturbed areas of 

the plant...” from lines 37 through 39, they are 

unnecessary if the sentence discussing construction of 

warehouses is deleted. 

9-ib-ED

236 4-43

"(McGovern, et.al. 2006)" is not listed as a reference in 

Section 4.12 of the DSEIS, and it should be made 

available to NSPM. 

9-ic-ED

237 4-47

The paragraph on lines 24 through 28 of page 4-47 

could be deleted. It provides the same information as 

the paragraph above it (lines 15 through 23).

9-id-ED

238 4-48

Delete sentence beginning "Currently zebra 

mussels........pools." There are zebra mussels in Pool 

3.

9-ie-ED

239 4-53 Replace "Lake Sturgeon" with "Sturgeon Lake." 9-if-ED

240 4-53 Delete "cumulative" from the first sentence of the 

discussion of Aquatic and Water Resources.

9-ig-ED

241 4-53 Delete "including refurbishment" from the 

Socioeconomics discussion. 

9-ih-ED

242 4-55 Delete this reference. It is part of the (USDOJ 2002) 

reference. 

9-ii-ED

243 4-56

The citation to (Hildebrandt 2008) should be (Hildebrant 

Iffert 2010). Add "Non-public reference per 36CFR 

800.11(c)."

9-ij-CR

244 4-56 This reference was not used in the text of Section 4. 9-ik-ED

245 5-4

Clarify the source of the dose to the population. Should 

note that this dose is an accident related dose and not a 

dose from normal operation.

9-il-ED
Appendix A

A-244

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

246 5-4 Replace "STGR" with "SGTR" in Table 5-2. 9-im-ED

247 5-6 Correct "developed B one." 9-in-ED

248 6-1 Replace "State" with "States". Replace "(ER; NMC 

2008)" with "(ER)(NMC 2008)."

9-io-ED

249 6-2 Replace "reclicensing" with "license renewal." 9-ip-ED

250 6-3 Correct the numbering of the bullets in lines 14 and 16. 9-iq-ED

251 7-1 Replace “Three Mile Island Nuclear Station, Unit 1, is...” 

with "PINGP 1 and 2, are...".

9-ir-ED

252 8-4

The gas turbines themselves do not require condenser 

cooling; however, the heat recovery steam generator 

does. Though requiring less cooling water than a simple 

steam cycle unit, combined cycle plants still require a 

significant volume of cooling water.

9-is-ED

253 8-4

Spent catalyst is generally either regenerated for reuse, 

or the components are recycled for other uses. Very 

little material is actually disposed of as waste.

9-it-ED

254 8-5

A new gas-fired unit would not be subject to 40 CFR 

Part 60, Subpart D. It would be subject to 40 CFR 60, 

Subpart KKKK, “Standards of Performance for 

Stationary Combustion Turbines.”

9-iu-ED

255 8-5

Replace with "Additionally, construction of a new electric 

production facility of greater than 25 MWe capacity 

would trigger the state environmental review process, 

found in Minn. R. 4410. As part of the review, the 

Minnesota Pollution Control Agency (MPCA) requires 

the submission of an Air Emission Risk Analysis for 

hazardous air pollutants, and a Greenhouse Gas 

Emissions Evaluation."

9-iv-ED

256 8-6

The new plant would be subject to the continuous 

monitoring requirements for SO2 and NOx specified in 40 

CFR Part 75, and the CO monitoring requirements 

specified in 40 CFR Part 60.

9-iw-ED

257 8-8

Federal and state air emission standards are designed 

to protect the public, not occupational workers. 

Occupational exposure is governed under the 

Occupational Safety and Health Administration, per 29 

CFR.

9-ix-ED
Appendix A

A-245

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

258 8-8

Industrial fabric filters or electrostatic precipitators can 

be used to control particulate emissions. However, very 

rarely are these kinds of controls installed on natural gas 

plants. Natural gas is considered inherently clean for 

particulate matter, and additional controls are unlikely. 

This would be formalized in the Best Available Control 

Technology (BACT) analysis submitted with the air 

permit application.

9-iy-ED

259 8-9 Replace "collocated" with "co-located". 9-iz-ED

260 8-13

Spent catalyst is generally either regenerated for reuse, 

or the components are recycled for other uses. Very 

little material is actually disposed of as waste.

9-ja-ED

261 8-14 Replace "8.1.2" with "8.1.1." 9-jb-ED

262 8-15

The new plant would be subject to the continuous 

monitoring requirements for SO2 and NOx specified in 

40 CFR Part 75, and the CO monitoring requirements 

specified in 40 CFR Part 60.

9-jc-ED

263 8-15 Replace "8.1.2" with "8.1.1." 9-jd-ED

264 8-15 This discussion was not included in section 8.1.1. 9-je-ED

265 8-15

The wood-fired combustion facility would be subject to 

different Federal and state air regulations than the 

combined-cycle natural gas plant. The wood fired boiler 

would likely be subject to 40 CFR Part 60, Subpart D (or 

Da), and the electric utility MACT standard, which is 

currently under development at the EPA. The combined 

cycle natural gas plant would be subject to 40 CFR Part 

60, Subpart KKKK.

9-jf-ED

266 8-17, 18

This discussion seems to blend the conclusions for the 

wood-fired and gas-fired plants together. This makes 

the discussion confusing and disjointed. This section 

needs to be re-written in order to clarify the point the 

authors are trying to make.

9-jg-ED

267 8-17

Federal and state air emission standards are designed 

to protect the public, not occupational workers. 

Occupational exposure is governed under the 

Occupational Safety and Health Administration, per 29 

CFR.

9-jh-ED

268 8-21

For this alternative, neither of the existing PINGP units 

would continue to operate. There appears to be copy

error here.

9-ji-ED

269 8-23

Spent catalyst is generally either regenerated for reuse, 

or the components are recycled for other uses. Very 

little material is actually disposed of as waste.

9-jj-ED
Appendix A

A-246

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

270 8-25

This paragraph does not need to be included. This 

alternative does not include the construction of any new 

air emission units.

9-jk-ED

271 8-28

What is the basis for the conclusion that operating only 

one unit would reduce the impact on Archaeological 

Resources from Moderate to Small. The other unit 

would not be decommissioned until both units were 

removed from service. 

9-jl-CR

272 8-31 Clarify the reference. 9-jm-ED

273 9-1 Suggest providing table to summarize this information. 9-jn-ED

274 9-1 Revise "1 Category" to "one Category 2." 9-jo-ED

275 9-1 See comments on lines 9-10 of page 4-24. 9-jp-ED

276 9-1

The discussion of mitigation actions noted in lines 36 

through 39 on page 9-1 related to reducing the impact to 

peregrine falcons seems unnecessary based on the 

discussion in lines 18 through 24 on page 3-4.

Lines 18 through 22 on page 3-4 state that the falcon 

nest is far enough away from the ground and that steam 

generator replacement is not expected to cause 

significant noise or other types of disturbance to the 

birds. Based on that conclusion, why is it necessary to 

suggest a mitigation measure to limit activities during 

midday hours? 

Lines 22 through 24 on page 3-4 note that the steam 

generator replacement will occur outside the falcon 

breeding period. Since the replacement is already 

planned to occur outside the breeding period, why is it 

necessary to note this as a possible mitigation measure? 

9-jq-ED

277 C-2

The discussion implies new permits are required, 

however, PINGP holds a Title V permit, which authorizes 

the installation and operation of all emission sources at 

the site. New or modified units may require an 

amendment to the permit prior to installation. The 

MPCA issues and enforces the permit.

9-jr-ED

278 C-4

The MPCA does not require a permit amendment for 

temporary emissions, such as those associated with the 

refurbishment. 

9-js-ED

279 D-71

Revise to read "... to replace the two steam generators 

at PINGP Unit 2 with replacement steam generators to 

support the extended life of PINGP Unit 2 through the 

period of extended operation." PINGP Unit 2 only uses

two steam generators, and the replacement steam 

generators are "recirculating vertical steam generators" 

(same as the original steam generators).

9-jt-ED
Appendix A

A-247

NSPM

Comment 

Number

Page 

Number Comment / Proposed Change

NRC

Comment 

ID

280 D-71, 

D-72

Replacement of the PINGP Unit 2 steam generators is 

scheduled for 2013, which is prior to the PEO for Unit 2. 

In line 44 on page D-71 and line 1 on page D-72, 

replace "...would replace steam generators only on Unit 

2 during the period of extended operation." with "...only 

the steam generators on Unit 2 must be replaced to 

support operation during the period of extended 

operation." 

9-ju-ED

281 D-77

The cooling towers are induced mechanical draft cross 

flow towers. Replace "Fans blow air up through the 

falling water" with "Fans draw air up through the streams 

of water" (Ref: USAR 11.6.2).

9-jv-ED

282 D-77 Revise to read "To minimize the impacts of the 

heated..." 

9-jw-ED

283 D-78 Reword to read "...order to prevent condenser inlet

temperatures from exceeding..."

9-jx-ED

284 D-80 Replace “Center” with “Services.” 9-jy-ED

285 F-4

What is the basis for the 5.1E-5 Unit 2 IPE value? 

NSPM did not provide a CDF for Unit 2 in the IPE, 

except to say that based on qualitative analysis it would 

be about the same as Unit 1.

9-jz-EP

286 F-4

What is the basis for the 5.1E-5 Unit 2 IPE value? 

NSPM did not provide a CDF for Unit 2 in the IPE, 

except to say that based on qualitative analysis it would 

be about the same as Unit 1.

9-ka-EP

287 F-11 Replace "Level 2" with "Level 1 plus LERF model." 9-kb-ED

288 F-11 Replace "Level 2 model" with "the Level 1 plus LERF 

and the full Level 2 model."

9-kc-ED

289 F-12 Change the second "Level 2" to "Level 1 plus LERF." 9-kd-ED

290 F-21 Table is missing entries for SAMAs 19, 20 and 22 and 

footnote (a). There appears to be a missing page.

9-ke-EP

291 F-22 Replace "potable" with "portable". 9-kf-ED
Appendix A

A-248

Commenter Number 9 – Mark Schimmel, Site Vice President, Prairie Island Nuclear Generating 

Plant (Cont.)

The following table contains various corrections and clarifications based on reference 

(Hildebrant Iffert 2010) that will be incorporated into SEIS Table 2-25.

Site 

Number

Site Name Description Current Condition Comment 

ID

21GD02 Bartron 

Site

Artifact 

Scatter—Base 

Camp (SHPO 

1996)

Disturbance on PINGP only: 70% moderately 

disturbed (by cultivation), 20% heavily 

disturbed (by historic and modern use), 10% 

completely destroyed (by archaeological 

excavation, borrow pit, road construction)

9-kg-CR

21GD58/

61

Birch Lake 

Mounds

Earthwork, 

Cemetery—

Mortuary 

(SHPO 1996)

Heavily (90%) disturbed (by railroad 

construction, cultivation, archaeological 

excavation)

9-kh-CR

21GD59 NSP II Site Earthwork 

(SHPO 1996)

Heavily disturbed/destroyed (by cultivation and 

construction of cooling towers); small areas 

may be capped by spoil deposits

9-ki-CR

21GD62 Birch Lake 

Mound

Earthwork 

(SHPO 1996)

Completely destroyed (by archaeological 

excavation)

9-kj-CR

21GD148 Cooling 

Tower Site 

Artifact Scatter 

(SHPO 1996)

Unassessed condition 9-kk-CR

21GD149 Substation 

Site

Artifact Scatter 

(Merjent 2009)

Unassessed condition 9-kl-CR

21GD207 Dike Site Artifact Scatter 

(SHPO 1996)

Unknown (no evidence of site in 2009) 9-km-CR

21GD277 Indian 

Slough 

Mound

Earthwork 

(Merjent 2009)

Minimally disturbed 9-kn-CR

21GD278 Otto Phlika 

Farmstead

Farm (Merjent 

2009)

Moderately disturbed 9-ko-CR

21GD279 Kuhns 

Farmstead

Farm (Merjent 

2009)

Moderately disturbed 9-kp-CR

21GD280 Reliance 

Stove Door 

Site

Artifact 

Scatter, 

Possible 

Homestead 

(Merjent 2009)

Unassessed 9-kq-CR

21GDl Vergil 

Larson 

Mounds II

Earthwork 

(OSA 1999)

Not field verified 9-kr-CR

--- Prairie 

Island

Schoolhouse Site

Schoolhouse 

(Merjent 2009)

Unassessed 9-ks-CR
A-249

COMMENTER 10 – Michael Schweyen, No affiliation given.

The following pages contain the comments made by Michael Schweyen during the evening 

session of the NRC public meetings held on 

December 17, 2009, on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-250

10-a-SR
Appendix A

A-251

10-a-SR

cont

10-b-NS
Appendix A

A-252

10-c-RW

10-d-RW
Appendix A

A-253

10-d-RW

cont
Appendix A

A-254

10-d-RW

cont
Appendix A

A-255

Commenter Number 11 – Kristen Eide-Tollefson

The following pages contain the comments sent by e-mail from Kristen Eide-Tollefson on the 

Draft Supplemental Environmental Impact Statement for the Prairie Island Nuclear Generating 

Plant license renewal.
Appendix A

A-256

From: healingsystems69@gmail.com on behalf of Kristen Eide-Tollefson 

[healingsystems@earthlink.net]

Sent: Sunday, January 31, 2010 1:26 AM

To: PrairieIslandEIS Resource

Cc: Kristen Eide-Tollefson

Subject: Re-sending Comments on DEIS - PINGP Study Group

Attachments: PINGP ADVISORY BRIEF(08-509, 08-510,08-690).pdf; PINGP Conversion 

Feasibility Study Exhibit 57.pdf; Sequence of Events for Extended Dry Cask 

Storage EPRI.pdf; Adaptive Management.doc

Please note: 3 attachments were not sent with initial transmission. Please advise if there is any problem 

accepting these comments. Thank you. 

Dear Sir:

When Xcel's application was made, and NRC's review was begun - the fate of Yucca Mountain was still 

uncertain. Secretary Chu's January 15th announcement that "Yucca Mountain is off the table" (Reuters) 

confirms a long line of administrative moves throughout 2009 -- which have culminated in the elimination 

of Yucca Mountain as the nation's permanent repository. This is new, significant information -- and a 

changed circumstance that fundamentally alters the landscape of license renewal for the Prairie Island 

plant. The NRC DEIS must evaluate and address it. 

If there is no repository, host states, local and tribal governments cannot count on completion of 

decommissioning, and removal of the waste within decommissioning time lines, or even within the time 

frame of the nuclear waste confidence decision. Without this assurance, land cannot be reused. And 

deterioration of temporary nuclear waste storage facilities will create safety, health, ecological costs and 

hazards -- that are neither described nor estimated in the DEIS. The combined strategies of the NRC 

GEIS and site specific evaluation for reactor refurbishment and relicensing -- and therefore the current 

DEIS -- are inadequate to address this new development. NRC must consider applying CEQ's NEPA's 

recommended Adaptive Management strategies to long term, at reactor storage. 

Please find attached the PINGP Study Group Advisory Brief to the Minnesota PUC dockets on expanded 

storage to accommodate the relicensing of the PINGP reactors 1 & 2. 

The study group finds that the elimination of Yucca Mountain from consideration as a permanent 

repository, requires additional considerations from NRC in the EIS. Specifically, the EIS should address: 

1. Cumulative effects of skyshine radiation with larger numbers of casks, as discussed in our brief; 

2. Additional monitoring as discussed in our brief to support a long term strategic adaptive management 

plan; 

3. Environmental Justice considerations as discussed in our brief; 

The development of additional information and analysis to address and mitigate indefinite at 

reactor site storage is essential: 

1. A full Environmental Site Assessment to support strategic long term management; 

2. Convening of an Adaptive Management Workgroup (see attachment: Adaptive Management);

11-a-RW

11-b-RW
Appendix A

A-257

3. A recommended timeline for cask and facility replacement, using the Yucca Mountain No-action 

engineering studies on factors for cask and facility degradation;

4. Discussion of provision for wet and dry transfer capacity for long term storage as per attached EPRI 

diagrams on Sequence of Events for Extended Dry Cask Storage. Also for security and safety for 

extended storage - from the 100 to 500 years discussed in the recent GAO report;

5. Discussion of what an Adaptive Management Plan for long term waste storage at PINGP would look 

like (see attachment: Adaptive Management);

6. Reevaluation of alternatives, specifically conversion, replacement or repowering of the PINGP with 

combined cycle gas turbines, in light of irreversibility of commitment of resources (see attachment: PINGP 

Conversion Feasibility Study Exhibit 57); 

Also, submitted along with the written comments were four other documents which were 

determined to be Out of Scope (OS.) The documents are:

1. A page from the NEPA Task Force (2002-2004) Modernizing NEPA Implementation 

Report outlining Chapters 3, Programmatic Analyses and Tiering and Chapter 4, 

Adaptive Management and Monitoring. ADAMS Accession Number ML100840639.

2. Feasibility Study for Conversion of Prairie Island to Natural Gas Fired Generation. 

November 20, 2002. Utility Engineering. ADAMS Accession Number ML100840642.

3. EPRI (Electric Power Research Institute) Presentation entitled, “Issues Related to 

Long-term Dry Storage of Used Nuclear Fuel.” Presented at Nuclear Waste 

Technical Review Board Meeting, Las Vegas, NV. June 11, 2009. ADAMS 

Accession Number ML100840610.

4. Advisory Brief of PINGP Study Group for State of Minnesota, Office of Administrative 

Hearing for the Public Utilities Commission, September 11, 2009. ADAMS Accession 

Number ML100840640.

11-b-RW

cont

11-e-OS

11-f-OS

11-d-OS

11-c-OS
Appendix A

A-258

Commenter Number 12 - Kenneth Westlake, U. S. Environmental Protection 

Agency

The following pages contain the written comments submitted by the U.S. Environmental 

Protection Agency on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-259
Appendix A

A-260
Appendix A

A-261

12-f-HH

12-e-HH

12-d-HH

12-c-HH

12-a-ED

12-b-HH

12-g-HH

12-h-EP
Appendix A

A-262

12-k-CI

12-h-EP

Cont

12-i-EJ

12-j-CR

12-l-CI

12-m-EP

12-n-EP
Appendix A

A-263

12-o-EP

12-p-SD

12-r-AR

12-s-NO

12-q-AR

12-t-OS
Appendix A

A-264

12-t-OS

cont

12-u-OS

12-v-TR

12-w-ED
Appendix A

A-265

12-w-ED 

cont

12-y-ED

12-x-ED

12-ac-ED

12-aa-ED

12-ab-ED

12-z-ED

12-ad-ED
Appendix A

A-266

Commenter Number 13 – Victoria Winfrey, President, Prairie Island Indian 

Community

The following pages contain the comments made by Victoria Winfrey, Prairie Island Indian 

Community, during the afternoon session of the NRC public meetings held on 

December 17, 2009, on the Draft Supplemental Environmental Impact Statement for the Prairie 

Island Nuclear Generating Plant license renewal.
Appendix A

A-267

13-a-NS

13-b-GW
Appendix A

A-268

13-c-OR
Appendix A

A-269

COMMENTER 14 – Gail Vaughn, No affiliation given.

The following page contains the comments submitted by e-mail from Gail Vaughn on the 

Supplemental Environmental Impact Statement for the Prairie Island Nuclear Generating Plant 

license renewal.
Appendix A

A-270

From: Gail Vaughn [vaughn.gail@gmail.com]

Sent: Tuesday, December 15, 2009 1:00 PM

To: Keegan, Elaine

Subject: public comment on Prairie Island nuclear plant license renewal

Dear Ms. Keegan,

I only just now received notice from the NRC of this public hearing tomorrow:

NRC SEEKS PUBLIC COMMENTS ON DRAFT ENVIRONMENTAL REPORT FOR PRAIRIE 

ISLAND NUCLEAR PLANT LICENSE RENEWAL

The notice I have in hand says that yesterday was the deadline for registering to comment at 

this hearing. That deadline is passed, but I am writing you anyway.

I cannot attend tomorrow's hearing in person. The weather is too bitter for me to be away from 

my wood-heated cabin for long enough to travel to Red Wing for the afternoon.

I live in Ferryville Wisconsin, right on the Mississippi River. So I am a direct downriver 

'beneficiary' of the radioactive pollutants emitted by the Prairie Island nuclear reactors.

I have been living in hope that they would be shut down in the next couple of years, as their 

licenses dictate. I have been hoping that we could make it successfully to shutdown without a 

really major accident at Red Wing, and that the environs could then start to heal. This 

happened in my own neighborhood when the reactor at Genoa WI was shut down, in the 80's; 

after that shutdown, the cancer rates in the neighborhood began to go down to more normal 

levels.

But no, Xcel wants to continue operating the reactors for much longer, and not only that, but 

increase the rate at which they run.

They PROMISED they would abide by the original deadlines, and they PROMISED they would 

not come back for more nuclear waste storage on site at Prairie Island; but they can't keep 

promises. They will never stop operating these facilities, as long as the

govt. lets them run them, until something goes really really wrong.

We have never come up with a solution for long-term storage of nuclear waste. It is morally 

wrong to continue to manufacture this waste and expect our children to come up with a storage 

solution. The electricity will be long gone by then. It will be much as it is at Genoa, where they 

pay over a million $ a year to baby-sit the nuclear waste there, even though there hasn't been 

any electricity since the 80's. I have never seen a single light bulb lit by the power from that 

reactor. A million dollars a year is a large burden for the ratepayers of a small cooperative 

utility. The Prairie Island legacy will dwarf that.

Please DENY the permit for continued operation of these reactors. They should be shut down 

ASAP, not allowed to operate even longer, and faster. The situation reminds me very much of 

the voyage of the Titanic, where they noted that there were many icebergs in their lane, but 

inexplicably they decided to SPEED UP.

Ever since then, the very name has been associated with folly and disaster.

14-a-OR

14-b-RW

14-C-OR
Appendix A

A-271

Please accept this heartfelt comment for your public comment files: SHUT THEM DOWN.

I cannot think of a more important issue for the health and safety of the upper Midwest.

Thank you.

-Gail Vaughn

Ferryville WI 54628
Appendix A

A-272

RESPONSES TO ENVIRONMENTAL JUSTICE, SOCIOECONOMICS, LAND USE, and 

HISTORIC and ARCHEOLOGICAL RESOURCES COMMENTS

AR – Aquatic Resources

Comment Numbers: 2-a, 2-b, 2-c , 2-d, 2-e, 3-c, 3-d, 3-f, 5-a, 5-b, 6-f, 6-t, 6-ba, 9-gf, 12-q, 12-r.

Response: Most of the comments are related to the thermal impacts and ice cover thickness at 

Lake Pepin. 

The U.S. Environmental Protection Agency (EPA) and its designee, Minnesota Pollution Control 

Agency (MPCA) are responsible for regulating cooling water discharges of PINGP 1 and 2 

under the Federal Water Pollution Control Act (Clean Water Act). Industrial, non-radioactive 

liquid releases from PINGP 1 and 2 are controlled by the National Pollution Discharge 

Elimination System (NPDES) and State Disposal System (SDS) permits, which are issued and 

enforced by MPCA. These permits are issued for 5-year intervals. NSP and MPCA can 

negotiate parameter limits in the NPDES and SDS permits, and the draft permits are made 

available by the MPCA to the public for review and comment. Section 2.1.6.3 of the SEIS, 

“Requirements under NPDES Permit,” describes the permitting requirements. SEIS Section 

4.5.3, “Heat Shock,” states, “NRC assumes that MPCA will continue to apply the best 

information available to future National Pollution Discharge Elimination System (NPDES) 

permits” to protect aquatic resources. 

SEIS Section 4.11.1, “Cumulative Impacts on Aquatic and Water Resources,” discusses the 

impact of plant operations on the amount of ice cover in Lake Pepin. The U.S. Army Corps of 

Engineers routinely monitors the thickness of ice cover in this section of the Mississippi River. 

As discussed in Section 4.11.1, the thermal effluent from PINGP 1 and 2 could be contributing 

to the deterioration of the Lake Pepin ice cover. If NSP does submit a license amendment 

application requesting a power uprate, any potential increases in the temperature of the thermal 

effluents will need to be addressed at that time.

No new and significant information was identified in these comments, except as described

below. Therefore, no changes to the SEIS were made.

Several of the comments are concerned with the drawdown of Pool 3. The drawdown of Pool 3 

is discussed in SEIS Section 4.11.2. No new and significant information was identified in these 

comments. Therefore, no changes to the SEIS were made.

Comment 2-a requests additional information on the impingement of the Higgins eye pearly 

mussel host species, as well as revisions to the quanity of listed Essential Habitats. Information 

relating to the impingement of the host species has been added to Section 4.7.1, “Aquatic 

Species.” This section states that the historic data shows all seven of the Higgins eye host 

species being impinged, within the cooling system at PINGP 1 and 2, in relatively small 

numbers. In order to minimize the impacts from the PINGP 1 and 2 cooling system, on 

entrainment and impingement of fish, the NPDES permit dictates the screen size the plant must 

use during the spring and summer.

Comment 2-c requests the addition of the Black Crappie to the list of suitable hosts for Higgins 

eye pearly mussel. The Black Crappie was added to the list located in Section 2.2.7,

“Threatened and Endangered Species.”
Appendix A

A-273

Comment 2-d requests that Xcel energy use cooling towers to the maximum extent practicable. 

The authority to determine acceptable thermal impacts is regulated by the NPDES and the State 

Disposal System permit. As described in Section 3.1, “Cooling and Auxillary Water Systems,”

the thermal limitations require temperature monitoring at five different locations: the discharge 

canal outfall (SD 001), the plant intake (SW 002), a specified point in the main river channel 

(SW 003), a specified point in Sturgeon Lake (SW 004), and a point directly downstream of Lock 

and Dam No. 3 (SW 001) which is to be monitored using three different temperature probes. 

The permit states that the daily average temperature should under no circumstances exceed 

86 °F (30 °C) and that the temperature of the receiving water should not raise over 5 °F (2.8 °C) 

above the ambient water temperature. The permit specifies that if the ambient water 

temperature reaches 78 °F (26 °C) for two consecutive days, all cooling towers should operate 

to their maximum extent.

Comment 3-f concerns NSP plans to dredge a 16-acre area in the Mississippi River near the 

PINGP site. The NRC requested and received additional information from NSP regarding this 

dredging project. The dredging activities took place in April 2010. Prior to dredging activities, 

NSP had requested and received all necessary approvals from State authorities. Sections 

2.1.7.4, 2.2.7.1, and 4.7.1 of the SEIS have been updated to reflect the new information and to 

include an analysis of the effects that periodic larger scale dredging that may take place during 

the term of license renewal would have on threatened and endangered species.

 

Comments 12-q and 12-r question whether wetlands or floodplains will be impacted by 

refurbishment activities. No wetlands or floodplains would be affected by refurbishment 

activities. Section 3.2.1 of the final SEIS has been updated to include this statement.

CI – Cumulative Impacts

Comment Numbers: 3-b, 6-ai, 6-an, 6-ap, 12-k, 12-l

Response: These comments concern cumulative impacts related to license renewal from 

increased dry cask storage, increased thermal discharges as a result of a potential extended 

power uprate amendment, and NSP dredging activities at PINGP. At this time, NSP has not 

submitted an extended power uprate license amendment request. If NSP submits a request to 

amend PINGP 1 and 2 operating licenses to uprate their power, it must also submit an 

environmental report which describes the impacts to the environment as a result of the uprate. 

The staff will review the report and prepare an Environmental Assessment as part of the 

process to evaluate the request to amend the PINGP 1 and 2 operating licenses. Any 

environmental impacts caused by the extended power uprate cannot exceed NRC dose limits or 

criteria. Additionally, all non-radioactive liquid effluent releases, such as an increase in the 

temperature of the cooling water discharge, must meet the limits set by the MPCA in the 

NPDES and SDS permits. 

If NSP wishes to increase the number of dry spent fuel casks at its site-specific Independent 

Spent Fuel Storage Installation (ISFSI), then an amendment request to its ISFSI license must 

be submitted. Also, if NSP wishes to renew the ISFSI license, NSP must submit an application 

requesting license renewal. Both applications must be accompanied with an environmental 

report which discusses the environmental impacts of the proposed actions, and NRC will 

conduct an environmental review in accordance with NEPA requirements. 

No new and significant information was identified in these comments. While NRC has not 

received amendment requests for the power uprate or increasing the number of casks at the 
Appendix A

A-274

ISFSI or a license renewal request for the ISFSI, Section 4.11 of the SEIS has been revised to 

include possible impacts to human health, cultural resources and socioeconomics from these 

three possible actions.

CR – Cultural Resources

Comment Numbers: 6-c, 6-k, 6-l, 6-m, 6-n, 6-o, 6-s, 6-ag, 6-ah, 6-aj, 6as, 6ab, 8-b, 8-c, 8-d, 8-f, 

8-g, 8-h, 8-j, 8-k, 8-l, 9-ej, 9-ek, 9-el, 9-em, 9-en, 9-eo, 9-ep, 9-eq, 9-er, 9-es, 9-et, 9-eu, 9-ev, 9-

ew, 9-ex, 9-ey, 9-ez, 9-fa, 9-fb, 9-fd, 9-fe, 9-ff, 9-fg, 9-fh, 9-fi, 9-fj, 9-fl, 9-fm, 9-fn, 9-fo, 9-fp, 9-fq, 

9-gl, 9-gw, 9-ho, 9-hp, 9-hq, 9-hr, 9-hs, 9-ht,9-hu, 9-hv, 9-hw, 9-hx, 9-hy, 9-ij, 9-jl, 9-kg, 9-kh, 9-

ki, 9-kj, 9-kk, 9-kl, 9-km, 9-kn, 9-ko, 9-kp, 9-kq, 9-kr, 9-ks, 12-j

General Response: A number of these comments relate to information presented in the 

Hildebrandt-Iffert 2010 reference document which updates information presented in the 

Hildebrant 2008 reference. NRC staff received this document in August 2010 and then 

reviewed the document. Changes to Chapters 2 and 4 of the SEIS were made as a result of the 

information presented in the Hildebrandt-Iffert 2010 reference document. 

A number of the comments relate to the mounds excavated in conjunction with the construction 

of PINGP 1 and 2. Five out of eight mounds in the Birch Lake Mound Group (21GD58/61) were 

excavated as part of Elden Johnson’s survey work in 1968, prior to and in conjunction with the 

construction of PINGP 1 and 2. The impact of plant construction on the Birch Lake Mounds was 

considered minimal. Human remains and funerary objects were recovered from this site. The 

Minnesota Historic Society (MNHS), Minnesota Indian Affairs Council, and Hamline University 

are working on the repatriation of these remains.

Archaeological practices in the late 1960s differed significantly from techniques utilized today. 

In the mid-1970s, there was a shift in attitudes towards excavating burial mounds, beginning 

with a voluntary ban on excavating Native American burials and mounds. By the late 1970s, 

comprehensive protection emerged for pre-contact burials and internments (including mounds) 

on both public and private lands. 

NSP has developed and implemented improved procedures that consider the impacts of plant 

operations on historic and archaeological resources and provide guidance for ground-disturbing 

activities. These procedures, along with training of environmental personnel will assist NSP in 

making informed decisions for various onsite projects. Any ground-disturbing activity that 

disturbs more than 6 inches in depth requires approval from the Site Environmental Coordinator. 

The excavation and trenching control procedures have drawings and illustrations to assist users 

in identifying culturally-sensitive areas, and pictures of artifacts that are prevalent in the area of 

the plant site. The coordinator will also rely on information found in the Cultural Resources 

Management Plan. 

The revised procedures were developed in consultation with the Minnesota Historical Society, 

the Bureau of Indian Affairs, the Office of the State Archaeologist, the Prairie Island Indian 

Community, and the NRC. Any modifications to NSP procedures and assessments regarding 

historic and archaeological resources will be coordinated with the consulting parties.

In addition to procedures, NSP conducted additional field surveys to locate known 

archaeological sites to determine their boundaries. The applicant also conducted a survey of 

the disturbed areas within the plant’s boundaries. NSP will use the results of these surveys to 

designate areas for archaeological protection.
Appendix A

A-275

NSP has prepared and implemented a Cultural Resources Management Plan (CRMP) to protect 

significant historical, archaeological, and cultural resources that may currently exist on the 

PINGP site. NSP will also conduct botanical surveys to identify culturally- and medicinallyimportant species on the plant site, and incorporate provisions to protect such plants into the 

CRMP. Additionally, NSP will consult with a qualified archaeologist prior to conducting any 

ground-disturbing activity in any area designated as undisturbed and in any disturbed area that 

is described as potentially containing archaeological resources.

Human remains and funerary objects were recovered from mound site 21GD62. The MNHS, 

Minnesota Indian Affairs Council, and Hamline University are working on the repatriation of 

these remains. The PIIC has requested (through the Minnesota Indian Affairs Council) that the 

human remains from this mound group be returned so they can be properly repatriated.

No ground-disturbing activities are currently planned in the location of the NSP Mound Group II. 

In the event that an undertaking is proposed, surveys would be warranted. Consultation would 

be required with the NRC, PIIC, and SHPO.

The NRC contacted the Advisory Council on Historic Preservation (ACHP) to initiate the Section 

106 consultation process by letter dated July 10, 2008 (ML081850189). In this letter, the NRC 

notified the ACHP of the proposed action (PINGP license renewal) and informed them that the 

staff’s Section 106 review would be coordinated through the National Environmental Policy Act 

in accordance with 36 CFR 800.8(c). Additionally, the staff informed the ACHP that the NRC 

entered into a Memorandum of Understanding (MOU) with the Prairie Island Indian Community 

(PIIC) for the PINGP license renewal environmental review.

A copy of this letter is located in Appendix D of the SEIS and is referenced in Section 4.9.6. A 

copy of the draft SEIS was sent to the ACHP. The ACHP did not provide comments. 

No new and significant information was identified in these comments. Therefore, no changes to 

the SEIS were made.

A number of comments relate to the terminology used in the SEIS to discuss historic and 

archaeological resources in general. This subject matter heading is consistent with NRC 

regulations at 10 CFR Part 51.53(c)(ii)(K) and Table B-1 to Appendix B to Subpart A of Part 51. 

The NRC considers historic and archaeological resources as an all-inclusive term that includes 

prehistoric, historic, and cultural properties. 

Existing conditions (cultural resources and historic properties) in the area of potential effects 

(APE) are described in Chapter 2. The text in Chapter 2 discusses the cultural history, 

background, and the known historic and archaeological resources at the PINGP site and the 

surrounding area to provide context for the resources that have been found within the APE. 

This section also discusses previous archaeological research that has been completed at 

PINGP. The discussion of the proposed action (undertaking) along with NRC’s impact 

assessment (direct and indirect effects), and consultation with the SHPO defining the APE are 

discussed in Chapter 4, Section 4.9.6. The section also provides a summary of the Section 106 

consultations to date. Appendix D provides the consultation correspondence with consulting 

parties including the SHPO. 

The NRC acknowledges that traditional cultural properties apply to all Americans (see National 

Register Bulletin 38:1). Burial mounds are typically considered traditional cultural property to 

American Indian tribes. 
Appendix A

A-276

There are no known historic properties within the developed portions of the PINGP site where 

temporary buildings would be constructed in support of the Unit 2 steam generator replacement 

project. NSP plans to use the same areas of the PINGP site that were utilized during the 

replacement of the Unit 1 steam generators. Utility service connections for the temporary 

buildings would be made on the surface and above ground. Prior to construction of PINGP, the 

land was farmed. As a result of construction, the developed parts of the power plant that would 

be utilized for the steam generator replacement project were heavily disturbed. 

The survey work was conducted in accordance with an agreement between NSP and the PIIC. 

No subsurface testing was conducted to address concerns regarding the possible disturbance 

to burial sites in accordance with this agreement. 

The MODERATE finding was determined on the basis that NSP’s procedures were not fully 

protective of historic and archaeological resources at PINGP 1 and 2. NSP has revised 

procedures to ensure the protection of historic and archaeological resources and to provide 

guidance to PINGP site personnel. These procedures, along with training of PINGP site 

personnel, will assist NSP in making informed decisions for various onsite projects. The revised 

procedures were developed in consultation with the Minnesota Historical Society, the Bureau of 

Indian Affairs, the Office of the State Archaeologist, the PIIC, and the NRC. In addition to 

revising its procedures, NSP conducted additional field surveys of known archaeological sites to 

confirm the locations of recorded sites and to determine site boundaries.

NSP has also prepared a Cultural Resources Management Plan (CRMP) to protect significant 

historical, archaeological, and cultural resources at the PINGP 1 and 2 site. Additionally, NSP

has indicated that it will consult with a qualified archaeologist prior to conducting any grounddisturbing activity in any area designated as undisturbed and in any disturbed area that is 

described as potentially containing archaeological resources. 

No new and significant information was identified in these comments. Therefore, no changes to 

the SEIS were made.

ED – Editorial Changes to DSEIS

Comment Numbers: 8-a, 8-d, 8-e, 8-I, 9-a, 9-b,9-c, 9-d, 9-e, 9-f, 9-g, 9-h, 9-i, 9-j, 9-k, 9-l, 9-m, 

9-n, 9-o, 9-p, 9-q, 9-r, 9-s, 9-t, 9-u, 9-v, 9-w, 9-x, 9-y, 9-z, 9-aa, 9-ab,9-ac, 9-ad, 9-ae, 9-af, 9-ag, 

9-ah, 9-ai, 9-aj, 9-ak, 9-al, 9-am, 9-an, 9-ao, 9-ap, 9-aq, 9-ar, 9-as, 9-at, 9-au, 9-av, 9-aw, 9-ax, 

9-ay, 9-az, 9-ba, 9-bb, 9-bc, 9-bd, 9-be, 9-bf, 9-bg, 9-bh, 9-bi, 9-bj, 9-bk, 9-bl, 9-bm, 9-bn, 9-bo, 

9-bp, 9-bq, 9-br, 9-bs, 9-bt, 9-bu, 9-bv, 9-bw, 9-bx, 9-by, 9-bz, 9-ca, 9-cb, 9-cc, 9-cd, 9-ce, 9-cf, 

9-cg, 9-ch, 9-ci, 9-cj, 9-ck, 9-cl, 9-cm, 9-cn, 9-co, 9-cp, 9-cq, 9-cr, 9-cs, 9-ct, 9-cu, 9-cv, 9-cw, 9-

cx, 9-cy, 9-cz, 9-da, 9-db, 9-dc, 9-dd, 9-de, 9-df, 9-dg, 9-dh, 9-di, 9-dj, 9-dk, 9-dl, 9-dm, 9-dn, 9-

do, 9-dp, 9-dq, 9-dr, 9-ds, 9-dt, 9-du, 9-dv, 9-dw, 9-dx, 9-dy, 9-dz, 9-ea, 9-eb, 9-ec, 9-ed, 9-ef, 9-

eg, 9-eh, 9-ei, 9-fk, 9-fr, 9-fs, 9-ft, 9-fu, 9-fv, 9-fw, 9-fx, 9-y, 9-fz, 9-ga, 9-gb, 9-gc, 9-gd, 9-ge, 9-

gg, 9-gh, 9-gj, 9-gk, 9-gm, 9-gn, 9-go, 9-gp, 9-gq, 9-gr, 9-gs, 9-gt, 9-gu, 9-gv, 9-gx, 9-gy, 9gz, 

9ha, 9hb, 9-hc, 9-he, 9-hf, 9-hg, 9-hh, 9-hi, 9-hj, 9-hm, 9-ho, 9-hz, 9-ib, 9-ic, 9-id, 9-ie, 9-if, 9-ig, 

9-ih, 9-ii, 9-ik, 9-il, 9-im, 9-in, 9io, 9-ip, 9-iq, 9-ir, 9-is, 9-it, 9-iu, 9-iv, 9-iw, 9-ix, 9-iy, 9-iz, 9-ja, 9-

jb, 9-jc, 9-jd, 9-je, 9-jf, 9-jg, 9-jh, 9-ji, 9-jj, 9-jk, 9-jm, 9-jn, 9-jo, 9-jp, 9-jq, 9-jr, 9-js, 9-jt, 9-ju, 9-

jv,9-jw,9-jx,9-jy, 9-kb, 9-kc, 9-kd, 9-kf, 12-a, 12-w, 12-x,12-y, 12-z,12-aa, 12-ab, 12-ac, 12-ad

Response: These comments are suggested editorial changes needed to the SEIS. NRC staff 

agrees with many of these changes and has revised the appropriate sections of the SEIS

accordingly. Those comments with editorial changes that were not adopted are listed below.
Appendix A

A-277

Comment 8-a concerns suggested changes to the Executive Summary. The Executive 

Summary follows the same format for all Supplements to NUREG-1437. These changes were 

not incorporated. 

Comment 8-I suggests that the MOU with the PIIC be referenced in Appendix D. The 

correspondence with the PIIC requesting Cooperating Agency status and the MOU are already 

included in Appendix D. This change was not incorporated.

Comments 9-aj, 9-am, 9-aw, 9-bp, 9-bv, 9-bx, 9-ca, 9-cn, 9-cv, 9-db, 9-dl, 9-du, 9-ee, 9-ef, 9-eh, 

9-fv, 9-ho, 9-hp, 9-hq, 9-ic, and 9-jm concern specific references in the document. Some 

references sited in the text were not included in the reference sections and some references 

sited in the text appeared to be the incorrect reference. To the extent possible, the references 

have been verified and corrected.

Comment 9-v suggested that “is” be deleted from ALARA, however, As Low As is Reasonably 

Achievable is correct.

Comment 12-a suggests that EPA regulations be included in the reference section for Chapter 1 

of the SEIS. Chapter 1 describes the purpose and need for the proposed action. No EPA 

regulations were specifically mentioned in the chapter and therefore are not included in the 

Chapter 1 reference section. 

Comment 12-w concerns the NRC not adhering to government-wide requirements for 

documents to be written in plain language. This SEIS documents a number of technical issues. 

The NRC attempted to write the technical sections in plain language. 

Comment 12-x suggests that referring to the GEIS− NUREG-1437, Generic Environmental 

Impact Statement for License Renewal of Nuclear Plants− does not fulfill the government-wide 

directive of using “best available quality data.” The GEIS evaluates and documents those areas 

that are generic to all nuclear plants (Category 1 issues) and those areas which require sitespecific evaluations (Category 2 issues.) Category 1 issues need to be reviewed but if no new 

or significant information is identified then the finding in the GEIS is deemed appropriate. The 

Council on Environmental Quality’s regulations allow for the SEIS to be tiered off the GEIS. 

Those areas identified as Category 2 issues are fully evaluated and documented in the SEIS. 

EJ – Environmental Justice

Comment Number: 4-I, 6-p, 6-q, 6r, 6-ab, 6-ac, 6-ak, 6-al, 6-am, 6-au, 6-at, 12-i

Response: Comment 4-l expresses concern that the lack of an effective Emergency Response 

Plan will have a severe impact on the immediate area owned or held in trust for the Prairie 

Island Indian Community. Potential impacts to minority and low-income populations and the 

PIIC are discussed in Section 4.9.7, “Environmental Justice,” of the SEIS. The Commission has

determined that there is no need for a special review of emergency planning issues in the 

context of an environmental review for license renewal. Therefore, decisions and 

recommendations concerning emergency preparedness at nuclear plants are ongoing and 

outside the regulatory scope of license renewal. This comment does not present any new and 

significant information. Therefore, no changes were made to the SEIS.

Response: Comment 6-p is concerned with the impact of refurbishment activities associated 

with the PINGP Unit 2 steam generator replacement project. NSP has stated that steam 
Appendix A

A-278

generator replacement activities would be limited to the previously-disturbed, developed 

portions of the plant site. Section 3.2.9 discusses the potential impacts to historic and 

archaeological resources at the PINGP site. This comment does not present any new and 

significant information. Therefore, no changes were made to the SEIS.

Response: Comments 6-q and 12-i are concerned with transportation impacts associated with 

the PINGP Unit 2 steam generator replacement project and whether proposed mitigation would 

be implemented. NSP has expressed a willingness to work with the PIIC to coordinate and 

implement appropriate measures to mitigate the transportation impacts relating to the Unit 2 

steam generator replacement activities. Mitigation actions include using NSP’s private access 

road for heavy truck traffic related to the project, using local law enforcement to control traffic 

during PINGP shift changes, and, if necessary, staggering the work schedule for steam 

generator replacement. Section 3.2.3 of the SEIS has been revised to reflect these changes.

Response: Comment 6-r is concerned with noise impacts associated with the PINGP Unit 2 

steam generator replacement project and whether proposed mitigation would be implemented. 

Given the industrial nature of the station, noise emissions during steam generator replacement 

would be intermittent. These impacts would be of short duration (similar to the PINGP 

Unit 1 steam generator replacement) and are not expected to be high. This comment does not 

present any new and significant information. Therefore, no changes were made to the SEIS.

Response: Comments 6-ab and 6-ac indicates that using the term “subsistence consumption” 

should not be used in conjunction with sampling the City of Red Wing’s drinking water. The 

NRC does not question the existence of subsistence consumption behavior in the 50-mile 

population surrounding the PINGP site. The NRC staff reviewed the results of NSP’s 

radiological environmental monitoring program (REMP). In accordance with the REMP, NSP 

takes water samples both upstream (control sample location) and downstream (indicator sample 

location) of the PINGP site. The City of Red Wing is one of the drinking water sample locations 

downstream of the PINGP site. The City of Red Wing sample location is used to show whether 

tritium from PINGP 1 and 2 could affect any individuals exhibiting subsistence consumption 

behavior downstream of the plant. Based on this data, the NRC staff concluded that no 

disproportionately high and adverse human health impacts would be expected in special 

pathway receptor populations located in Red Wing or anywhere else as a result of subsistence 

consumption of fish and wildlife downstream of the PINGP site. 

NSP has indicated that the practice of discharging turbine building sump water into a landlocked 

area was discontinued in 2009. Section 4.8.1 of the SEIS has been revised to reflect this 

change. Comments 6-ak, 6-al, and 6-am indicate that NRC did not comment or analyze the 

sections of the draft SEIS provided by PIIC. NRC assessed but did not comment on statements 

PIIC provided for the draft SEIS because, as a cooperating agency in the development of the 

draft SEIS, PIIC was entitled to have its views published in unedited form. These comments do 

not present any new and significant information. Therefore, no changes were made to the 

SEIS.

Response: Comment 6-au indicates that the SEIS did not discuss possible mitigation strategies 

that NSP could adopt or implement to reduce impacts to the PIIC. NSP has expressed a 

willingness to work with the PIIC to coordinate and implement appropriate mitigation measures

on several impact issues including four license renewal commitments to address the protection 

of archaeological, historical, and cultural resources. These comments do not present any new 

and significant information. Therefore, no changes were made to the SEIS.
Appendix A

A-279

Response: Comment 6-at indicates that NRC did not analyze environmental justice cumulative 

impacts. The staff has revised section 4.11.4 to address environmental justice cumulative 

impacts associated with reasonably foreseeable future actions at the PINGP site including EPUrelated plant modifications and ISFSI expansion.

EP – Emergency Planning – Postulated Accidents 

Comment Numbers: 4-b, 4-e, 4-g, 4-h, 4-l, 6-aw, 9-jz, 9-ka, 9-ke, 12-h, 12-m, 12-n, 12-o

Response: These comments generally indicate that PINGP’s emergency response plan should 

be reviewed as part of the license renewal process or that the EP is deficient. 

In the rulemaking process for developing regulations for license renewal, the Commission 

considered the need for a review of emergency planning issues. As discussed in the 

Statements of Consideration (56 FR 64966), the programs for emergency preparedness at 

nuclear power plants apply to all nuclear power licensees and require specific levels of 

protection regardless of plant design, construction or license date. Regulations and 

requirements for emergency planning are at 10 CFR 50.47 and Appendix E to 10 CFR Part 50. 

These requirements apply to all operating nuclear power plants and will continue to apply to 

plants with renewed licenses. Through the NRC’s regulations, required exercises, and Reactor 

Oversight Process inspections, NRC reviews existing emergency preparedness plans 

throughout the life of a plant. Therefore, NRC has determined that reviewing a plant’s 

emergency plan as part of the license renewal process is not needed. 

The comments do not provide new and significant information. Therefore, no changes have 

been made to the SEIS. 

In regard to comments expressing concern about terrorists’ activities and long-term spent fuel 

storage, appropriate safeguards and security measures have been incorporated into a site’s 

security and emergency plans. Any changes required to be made to the security or emergency 

plan as a result of potential terrorist events will be incorporated and reviewed under the 

operating license, and therefore, are independent of license renewal. 

The comments do not provide new and significant information. Therefore, no changes have 

been made to the SEIS.

GW – Ground Water

Comment Numbers: 1-b, 1-c, 4-c, 6-w, 6-aa, 6-ab, 6-ac, 6-ad, 6-ae, 13-b

Response: These comments are concerned with tritium in the ground water. NRC regulations 

require licensees to control and limit radioactive releases, including tritium, to the environment 

(the air and water) in very small amounts. As part of the NRC requirements for operating a 

nuclear power facility, licensees must keep releases of radioactive material into the environment 

during normal operations as low as is reasonably achievable (ALARA), as required by 10 CFR 

Part 50.36a, and comply with radiation dose limits for the public in 10 CFR Part 20.

NSP conducts a radiological environmental monitoring program (REMP). The REMP includes 

measures to monitor the impacts to the environment and the public in the vicinity of the PINGP

site. NSP summarizes data from the sampling results of the REMP in a report and compares 

the results to NRC standards. NSP is required to submit a copy of the REMP monitoring report 

to the NRC annually. NSP also monitors and evaluates liquid and gaseous effluents released 

from the plant. NSP also summarizes effluent releases in an annual report that it submits to the 
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NRC. The reports are available on the NRC’s public website at 

http://www.nrc.gov/reactors/operating/ops-experience/tritium/plant-info.html. 

There are several factors that would contribute to the fluctuation in tritium concentration levels 

over time. The tritium could be residual activity from a previous leak or spill that is migrating 

through the soil or the result of “washout” from the routine release of gaseous effluents. Also, 

tritium is part of natural background radiation; it is produced in the atmosphere when cosmic 

rays collide with air molecules. As a result, tritium is found in small amounts in ground water

throughout the world. The SEIS reported the information to demonstrate that NSP has a 

monitoring program which routinely analyzes the levels of radioactive material in ground water. 

Since the levels are below NRC’s reporting values for environmental samples, the NRC 

considers the impact to be SMALL. While the evaluation performed for license renewal is done 

only once, the NRC’s on-going inspection program periodically inspects NSP’s radioactive 

effluent monitoring and radiological environmental monitoring programs for compliance with 

NRC’s radiation protection standards in 10 CFR Part 20. The NRC’s inspection program 

evaluates the data for compliance with radiation protection standards. If the data were to show 

a non-compliance with requirements, the NRC would take appropriate enforcement action.

No new and significant information is provided in these comments. Therefore, no changes have 

been made to the SEIS as a result of these comments. However, the staff updated the SEIS to 

include the radiological dose data from the PINGP 2009 radioactive effluent release report.

HH – Human Health

Comment Numbers: 6-d, 6-e, 6-g, 6-i, 6-af, 6-az, 9-hk, 9-jl, 12-b, 12-c, 12-d, 12-e, 12-f, 12-g

Response: These comments relate to the evaluation in the SEIS of the impact from PINGP 

operations on human health. The SEIS is a site-specific supplement to the extensive and 

thorough technical evaluation performed by the staff and presented in NUREG-1437, “Generic 

Environmental Impact Statement for License Renewal of Nuclear Plants” (GEIS). The GEIS 

examines the possible environmental impacts that could occur as a result of renewing licenses 

of individual nuclear power plants under 10 CFR Part 54. The GEIS, to the extent possible, 

establishes the bounds and significance of these potential impacts. The analyses in the GEIS 

encompass all operating light-water power reactors. For each type of environmental impact, the 

GEIS attempts to establish generic findings covering as many plants as possible. While plant 

and site-specific information is used in developing the generic findings, the NRC does not intend 

for the GEIS to be a compilation of individual plant environmental impact statements. 

The GEIS has three principal objectives: (1) to provide an understanding of the types and 

severity of environmental impacts that may occur as a result of license renewal of nuclear power 

plants under 10 CFR Part 54, (2) to identify and assess those impacts that are expected to be 

generic to license renewal, and (3) to support a rulemaking (10 CFR Part 51) to define the 

number and scope of issues that need to be addressed by the applicants in plant-by-plant 

license renewal proceedings. To accomplish these objectives, the GEIS makes maximum use 

of environmental and safety documentation from original licensing proceedings and information 

from State and Federal regulatory agencies, the nuclear utility industry, the open literature, and 

professional contacts.

In summary, the GEIS contains all the relevant background information on each technical issue 

evaluated in the SEIS. The SEIS is intended to be a supplement to the GEIS which presents 

information about the nuclear power plant being evaluated.
Appendix A

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These comments provided no new and significant information. Therefore, no changes have 

been made to the SEIS.

With regard to the comment to include the relative risk from tritium, the PINGP tritium sampling 

program is an on-site monitoring program designed to monitor the land nearest to the reactor for 

potential leaks from plant systems containing radioactive liquids. It is not designed to assess the 

impact to human health because ground water is not used for human consumption. It does not

monitor the routine discharges of radioactive liquid effluents into the Mississippi River from 

designated discharge points that are monitored and controlled. The plant has a radioactive 

liquid waste processing system, discussed in Section 2.1.2.1 of the SEIS, that is designed to 

identify, measure, and quantify radioactive effluents discharged into the public domain.

The addition of a ground water monitoring program to the REMP at nuclear power reactors is 

relatively new, and the staff believes it is appropriate to present the information in the SEIS. 

The discussion of radiation dose from all radioactive effluents is a separate issue for evaluation.

In Section 4.8.1 of the SEIS, the staff presents the radiological impacts from all radioactive 

effluents discharged from PINGP. The calculated dose to a member of the public, as calculated 

by the applicant, from radioactive effluents is well within the appropriate NRC radiation 

protection standard. 

This comment provided no new and significant information. Therefore, no changes have been

made to the SEIS.

Regarding the comments asking about cancer studies in the vicinity of nuclear power plants, a 

number of studies have been performed to examine the health effects around nuclear power 

facilities. The following is a list of some of the studies that have been conducted.

• In 1990, at the request of Congress, the National Cancer Institute conducted 

a study of cancer mortality rates around 52 nuclear power plants and 10 other 

nuclear facilities. The study covered the period from 1950 to 1984 and 

evaluated the change in mortality rates before and during facility operations. 

The study concluded there was no evidence that nuclear facilities may be 

linked causally with excess deaths from leukemia or from other cancers in 

populations living nearby. 

• Investigators from the University of Pittsburgh found no link between radiation

released during the 1979 accident at the Three Mile Island nuclear station 

and cancer deaths among nearby residents. This study followed more than 

32,000 people who lived within 8 km (5 mi) of the facility at the time of the 

accident. 

• In January 2001, the Connecticut Academy of Sciences and Engineering 

issued a report on a study around the Haddam Neck nuclear power plant in 

Connecticut and concluded that exposures to radionuclides were so low as to 

be negligible and found no meaningful associations to the cancers studied.

• In 2001, the American Cancer Society concluded that, although reports about 

cancer clusters in some communities have raised public concern, studies 

show that clusters do not occur more often near nuclear plants than they do 

by chance elsewhere in the population. Likewise, there is no evidence linking 

the isotope strontium-90 with increases in breast cancer, prostate cancer, or 

childhood cancer rates. 

• In 2001, the Florida Bureau of Environmental Epidemiology reviewed claims 

that there are striking increases in cancer rates in southeastern Florida 
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A-282

counties caused by increased radiation exposures from nuclear power plants. 

However, using the same data to reconstruct the calculations on which the 

claims were based, Florida officials did not identify unusually high rates of 

cancers in these counties compared with the rest of the state of Florida and 

the nation.

• In 2000, the Illinois Public Health Department compared childhood cancer

statistics for counties with nuclear power plants to similar counties without 

nuclear plants and found no statistically significant difference.

In summary, there are no studies to date that are accepted by the nation’s leading scientific 

authorities that indicate a causative relationship between radiation dose from nuclear power 

facilities and cancer in the general public. The amount of radioactive material released from 

nuclear power facilities is well measured, well monitored, and known to be very small.

Recently, the Nuclear Regulatory Commission has asked the National Academy of Sciences

(NAS) to perform a state-of-the-art study on cancer risk for populations surrounding nuclear

power facilities. The NAS study will update the 1990 U.S. National Institutes of Health−

National Cancer Institute (NCI) report, “Cancer in Populations Living near Nuclear Facilities.”

The study will be carried out in two consecutive phases. A Phase 1 scoping study will identify 

scientifically sound approaches for carrying out an epidemiological study of cancer risks. This 

scoping study began on September 1, 2010, and will last for 15 months. The result of this 

Phase 1 study will be used to inform the design of the cancer risk assessment, which will be 

carried out in a future Phase 2 study.

These comments provided no new and significant information. Therefore, no changes have 

been made to the SEIS.

LR – License Renewal Process

Comment Numbers: 3-a, 3-b, 4-a, 6-ax, 6-ay, 6-bb, 

Comment 3-a relates to a letter from the Minnesota Department of Natural Resources that was 

omitted from the draft SEIS published in October 2009. The letter identified three scoping 

issues; water level drawdowns, Lake Pepin ice cover, and PINGP communications tower. The 

Minnesota Department of Natural Resources reiterated these three issues in its letter dated 

January 29, 2010, transmitting comments on the draft SEIS. NRC responses to water level 

drawdown and Lake Pepin are in the comment response section on Aquatic Resources. No 

new and significant information was introduced. Therefore, no changes were made to the SEIS.

The remaining comments are questions asked by the PIIC as to which agencies the NRC 

consulted with specifically about the impact to the PIIC for PINGP 1 and 2 operations. The NRC 

consulted with the Minnesota State Historic Preservation Office (SHPO) relating to the impacts

of PINGP 1 and 2 operations on the cultural resources of the PIIC. As a result of this 

consultation, NSP revised procedures to ensure the protection of historic and archaeological 

resources and to provide guidance to PINGP site personnel. The NRC also consulted with 

Federal, State and local agencies such as the Bureau of Indian Affairs and Fish and Wildlife 

Service to obtain information about the impact to the environment from PINGP 1 and 2. The 

consultation with these agencies provided information on impacts of PINGP 1 and 2 operations 

on the resources of the surrounding areas, including those within and abutting the PIIC.

These comments provided no new and significant information. Therefore, no changes have 

been made to the SEIS.
Appendix A

A-283

MOU – Memorandum of Understanding with the Prairie Island Indian Community

Comment Numbers: 6-a, 6-b, 6-j, 6ao, 

These comments express concern and request clarity on the information provided in the SEIS 

on the Prairie Island Indian Community’s (PIIC) cooperating agency status. In 2008, the NRC 

and the PIIC signed a Memorandum of Understanding (MOU) granting cooperating agency 

status to the PIIC. The MOU recognized the PIIC’s special expertise and information relating to 

historic and archaeological resources, socioeconomics, land use, and environmental justice. 

Several meetings were held between the PIIC and NRC to fully understand those subject areas 

covered by the MOU. The PIIC has provided valuable input to the final SEIS, including 

archeological information and has provided written statements in the areas covered by the MOU 

which are incorporated into the SEIS. These statements can be found in Chapters 2, 3, 4, 5, 

and 8. They are included to present PIIC view-points on the areas covered by the MOU. 

Comment 6a requests the NRC to revise the Executive Summary to include information on the 

cooperating status of the PIIC. The executive summary has been revised to include the 

requested information. 

NO – Noise 

Comment Numbers: 9-gi, 12-s

Response: These comments express concern relating to the traffic effects and noise. The NRC 

agrees with the two comments. NSP has expressed a willingness to work with the PIIC to 

coordinate and implement appropriate measures to mitigate transportation impacts resulting 

from the PINGP Unit 2 steam generator replacement project.

The NRC is not aware of any noise monitoring conducted at PINGP during the development of 

the GEIS. License renewal would not add to the extent of noise impacts, either in frequency 

distribution or in intensity. During the license renewal term, noise impacts would be the same 

as during the initial license term. The 1996 GEIS determined this to be a Category 1 issue and 

noted that noise has not been found to be a problem at operating plants and is not expected to 

be a problem at any plant during the license renewal term.

The NRC reviewed and evaluated the PINGP ER, scoping comments, other available 

information, and visited the plant site and did not identify any new and significant information 

that would change the conclusions presented in the 1996 GEIS. Therefore, it is expected that 

there would be no impacts related to this Category 1 issue during the period of extended 

operation beyond those discussed in the GEIS. For PINGP 1 and 2, the NRC incorporates the 

GEIS conclusions of impacts by reference into the SEIS. 

The comments do not present any new and significant information. Therefore, no changes have 

been made to the SEIS.

NS – Nuclear Safety

Comment Numbers: 10-b, 13-a

Response: These are general comments expressing concern as to whether the nuclear plant is 

safe and if there is adequate monitoring. All operating power plants are required to have a

program in place for monitoring liquid and gaseous effluents and to have an environmental 

monitoring program. Plant safety systems are inspected by NRC resident and regional 
Appendix A

A-284

inspectors in accordance with the NRC’s Reactor Oversight Process. No new and significant 

information is provided. Therefore, no changes have been made to the SEIS.

OR – Opposed to License Renewal

Comment Numbers: 1-a, 1-e, 13-c, 14-a, 14-c

Response: These comments oppose renewal of the PINGP 1 and 2 operating licenses and are 

general in nature. The comments do not provide new and significant information. Therefore, no 

changes have been made to the SEIS.

OS – Out of Scope for License Renewal

Comment Number: 4-b, 4-m, 4-n, 4-o, 6-bd, 11-c, 11-d, 11-e, 11-f 12-t, 12-u

Response: These comments express concern regarding (1) tax revenue and converting PINGP 

1and 2 to natural gas-fired plants, (2) the Emergency Plan for the City of Red Wing, and (3) a 

copy of an Electric Power Research Institute (EPRI) presentation on dry storage of spent 

nuclear fuel. Included with these comments are written testimony submitted to the Minnesota 

Public Utilities Commission. The NRC has determined that these documents are out of scope

for license renewal. The need for electric power generation, the type of power plant, and how 

taxes are assessed and allocated are determined at the State and local levels of government. 

Determination of the adequacy of NSP’s emergency response planning is part of the NRC’s 

Reactor Oversight Process (ROP), which is applied to all operating reactors regardless of time 

in operation, rather than an issue considered separately in license renewal. 

No new and significant information was introduced. Therefore, no changes were made to the 

SEIS.

RW – Radiological Waste Issues

Comment Numbers: 1-c, 1-d, 6-n, 6-am, 6-aq, 6-ar, 6-av, 6-bb, 6-bc, 10-c, 10-d, 11-a, 11-b, 

14-b

Response: These comments express concern regarding the safe, long-term storage of spent 

nuclear fuel (SNF), especially in light of the fact that the U.S. Department of Energy has 

requested withdrawal of the license application for the high-level waste repository at Yucca 

Mountain in Nevada. 

As described in the Generic Environmental Impact Statement (GEIS), NUREG-1437, the 

storage of SNF is a Category 1 issue that is generic to all nuclear power plants. SNF must be 

stored in casks which are licensed by the NRC and transported in casks which are certified by 

the NRC. Regulations pertaining to the storage of SNF can be found in 10 CFR Part 72, 

“Licensing Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level 

Radioactive Waste, and Reactor-Related Greater Than Class C Waste.” Regulations for 

certifying transportation casks can be found in 10 CFR Part 71, “Packaging and Transportation 

of Radioactive Material.”

The safety and environmental effects of SNF have been evaluated by the NRC. NRC’s Waste 

Confidence Decision is codified at 10 CFR 51.23. The latest update to the Waste Confidence 

Decision was published in the Federal Register on December 23, 2010 (75 FR 81037). In the 

latest update, the Commission determined that long-term storage of SNF could be 

accomplished without significant environmental impact for at least 60 years beyond the licensed 

life for operation (which may include the term of a revised or renewed license). 
Appendix A

A-285

With regard to Comment 6-am, which expresses concern over the cumulative impact from the 

long-term storage of SNF, NSP must demonstrate that the EPA radiation dose limit 

(40 CFR Part 190) to a member of the public from all site sources does not exceed 25 millirems 

per year. As a facility increases its inventory of SNF, it must still demonstrate compliance with 

EPA’s dose limit.

Accordingly under 10 CFR 51.23(b), no site-specific discussion of any environmental impact of 

spent fuel storage in reactor facility storage pools or independent spent fuel storage facilities is 

required in an environmental impact statement associated with license renewal. 

No new and significant information was introduced by these comments. Therefore, no changes 

were made to the SEIS.

SD – Shutdown and Decommissioning

Comment Number: 12-p

This comment indicated that more information should be provided relating to the shutdown and 

decommissioning of PINGP 1 and 2. As described in the GEIS, decommissioning is a 

Category 1 issue. No new and significant information relating to decommissioning was 

identified by the NRC during the scoping process, its review of the applicant’s Environmental 

Report, or during the site audit that would alter its classification as a Category 1 issue. 

Therefore, no changes were made to the SEIS.

SE – Socioeconomics

Comment Numbers: 4-e, 4-f, 4-g, 4-j, 4-k

Response: These comments express concern over the decrease in tax revenue received and 

money available to provide emergency services in the City of Red Wing, Minnesota. Section 

2.2.8.7 of the draft SEIS describes the amount of taxes paid to Goodhue County, the City of 

Red Wing, and Public School District 256. As discussed, in Minnesota, public utilities are 

valued using cost and income approaches, and the Minnesota Department of Revenue 

determines how utility companies are valued. While improvements at PINGP 1 and 2 may 

increase the overall value of the plant, there is no guarantee that tax payments will remain at 

current levels. If NSP is allowed to continue to depreciate PINGP 1 and 2, tax payments to 

these jurisdictions will be decreased. In anticipation of a change in the utility company valuation 

rule, NSP executed revenue sharing agreements with the City of Red Wing and Goodhue 

County in November 2006 in order to stabilize these communities for their anticipated loss of 

property tax revenue. Nevertheless, the NRC does not evaluate the effects of the decrease in 

tax revenue to the City of Red Wing and its ability to provide essential public safety services and 

its affect on the “Emergency Response Program” in the SEIS.

The purpose and need for the proposed action (renewal of an operating license) is to provide an 

option that allows for power generation capability beyond the term of a current nuclear power 

plant operating license to meet future system generating needs, as such needs may be 

determined by State, licensee, and, where authorized, Federal (other than NRC) decision 

makers. The SEIS for license renewal is not required to address the economic costs and 

economic benefits of the proposed action or of alternatives to the proposed action (see 10 CFR 

51.95 (c)(2)). The NRC has no role in the decisions of State and local tax and utility officials in 

determining what is taxed, how taxes are collected, and how tax revenue is allocated, for 

example, to provide funding for emergency services. 
Appendix A

A-286

The NRC must have “reasonable assurance that adequate protective measures can and will be 

taken in the event of a radiological emergency.” The NRC’s decision of reasonable assurance 

is based on licensees complying with NRC regulations and guidance. The emergency plans for 

nuclear power plants cover preparations for evacuation, sheltering, and other actions to protect 

residents near plants in the event of a serious incident. Nuclear power plant owners, 

government agencies, and State and local officials work together to create a system for 

emergency preparedness and response that will serve the public in the unlikely event of an 

emergency. Federal oversight of emergency preparedness for licensed nuclear power plants is 

shared by the NRC and the Federal Emergency Management Agency (FEMA).

As part of the reactor oversight process, the NRC reviews licensees’ emergency planning 

procedures and training. The Commission considered the need for a review of emergency 

planning issues in the context of license renewal during its rulemaking proceedings on 

10 CFR Part 54, which included public notice and comment. Requirements related to 

emergency planning are in the regulations at 10 CFR 50.47 and Appendix E to 10 CFR Part 50. 

These requirements apply to all operating licenses and will continue to apply to facilities with 

renewed licenses. Through its standards and required exercises, the Commission reviews 

existing emergency preparedness plans throughout the life of any facility, keeping up with 

changing age, race, and ethnographic demographics and other site-related factors.

The Commission has determined that there is no need for a special review of emergency 

planning issues in the context of an environmental review for license renewal. Therefore, 

decisions and recommendations concerning emergency preparedness at nuclear plants are 

ongoing, as part of the regulatory oversight by the NRC irrespective of the operating age of the 

plant, and outside the regulatory scope of license renewal.

As noted in Comment 4-j, Section 4.9 on page 4-25 discusses generic socioeconomic issues. 

These comments, in addition to the referenced information presented to the Minnesota Public 

Utilities Commission, do not provide sufficient new and significant information that would change 

the conclusions presented in the GEIS. Since the NRC has no role in the decisions of State and 

local tax and utility officials in determining what is taxed, how taxes are collected, and how tax 

revenue is allocated, there would be no impacts related to the Category 1 issue in question 

during the period of extended operation beyond those discussed in the GEIS.

In addition, the discussion in Section 4.9.4 in the SEIS addresses tax revenue-related land use 

impacts during the license renewal term. Land use conditions in the City of Red Wing are not 

expected to change as a result of renewing PINGP 1 and 2 operating licenses beyond what has 

already been experienced since tax payments from NSP would continue. 

No new and significant information was introduced. Therefore, no changes were made to the 

SEIS.

Comment 9-hn questions the validity of the statement in the draft SEIS that the assessed value 

of PINGP 1 and 2 would not increase as a result of steam generator replacement. Based on 

further review, the text in Section 4.9.4 of the SEIS has been revised to indicate that the 

replacement of the Unit 2 steam generator could increase the assessed value of PINGP 1 and 2 

and property taxes could also increase.

SR – Support of License Renewal/Nuclear Power

Comment Numbers: 7-a, 9-a, 10-a
Appendix A

A-287

These are comments that are generally in support of relicensing PINGP. No new and 

significant information was introduced. Therefore, no changes were made to the SEIS.

TR – Terrestrial Resources

Comment Numbers , 2-f, 2-g, 3-e, 5-c, 6-u, 6-v, 6-x, 6-y, 9-hd, 12-v

Response: These comments express concern relating to the impacts of migratory birds. The 

comments cite the communications tower as a structure that has direct impacts to these 

species. During its environmental review, NRC staff reviewed information concerning impacts 

to migratory birds. No evidence exists that suggests that the communications tower on the 

PINGP site impacts migratory birds; therefore, no mention is made of the communications tower 

in the discussion of environmental impacts resulting from license renewal. No changes were 

made to the SEIS. 

Comment 6-v requests additional information relating to the MOU between Xcel Energy (Xcel) 

and Fish and Wildlife Services (FWS). The APP (Avian Protection Plan) for the State of 

Minnesota was approved by the FWS in February 2010, is valid indefinitely, and will be updated 

on an “as needed” basis. Xcel has since developed guidelines to standardize avian protection 

across all of the company’s operating divisions (which include both transmission lines 

associated and not associated with the operation of PINGP) as described in Section 3.1.6.3, 

“Avian Mortality Resulting from Collisions with Transmission Lines,” in the Prairie Island Nuclear 

Generating Plant, Environmental Report . As a result of the APP, Xcel has evaluated 

transmission lines, owned and operated by NSP, for the risk of migratory bird electrocution and 

collision. Those lines, that have been identified as having the highest risk, will be retrofitted or 

modified by NSP on a schedule that corresponds to regular line maintenance, starting in 2010 

and ending in 2014. 

Xcel Energy submits semi-annual reports to the FWS summarizing activities covered under the 

MOU, including avian injury or mortality. Section 4.6 of the SEIS discussed one incident in 2002 

that required an avian injury or mortality report. The final SEIS has updated information 

including an additional incident in 2008. These two incidents are the only reported avian injuries 

or mortalities since the MOU, related to the APP, was signed in 2002.

APPENDIX B

NEPA ISSUES FOR LICENSE RENEWAL OF 

NUCLEAR POWER PLANTS

B-1

B. NEPA Issues for License Renewal of Nuclear Power Plants

Table B-1. Summary of Issues and Findings. This table is taken from Table B-1 in 

Appendix B, Subpart A, to 10 CFR Part 51. Data supporting this table are contained 

in NUREG-1437, Generic Environmental Impact Statement for License Renewal of 

Nuclear Plants. Throughout this report, “Generic” issues are also referred to as 

Category 1 issues, and “Site-specific” issues are also referred to as Category 2 

issues.

Issue Type of Issue Finding

Surface Water Quality, Hydrology, and Use

Impacts of 

refurbishment on 

surface water

quality

Generic SMALL. Impacts are expected to be negligible during 

refurbishment because best management practices are 

expected to be employed to control soil erosion and 

spills.

Impacts of 

refurbishment on 

surface water use

Generic SMALL. Water use during refurbishment will not increase 

appreciably or will be reduced during plant outage.

Altered current 

patterns at intake 

and discharge

structures

Generic SMALL. Altered current patterns have not been found to 

be a problem at operating nuclear power plants and are 

not expected to be a problem during the license renewal 

term.

Altered salinity 

gradients

Generic SMALL. Salinity gradients have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal

term.

Altered thermal 

stratification of 

lakes

Generic SMALL. Generally, lake stratification has not been found 

to be a problem at operating nuclear power plants and is 

not expected to be a problem during the license renewal 

term.

Temperature effects 

on sediment 

transport capacity

Generic SMALL. These effects have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term.

Scouring caused by 

discharged cooling 

water

Generic SMALL. Scouring has not been found to be a problem at 

most operating nuclear power plants and has caused only 

localized effects at a few plants. It is not expected to be a 

problem during the license renewal term.

Eutrophication Generic SMALL. Eutrophication has not been found to be a 

problem at operating nuclear power plants and is not 

expected to be a problem during the license renewal 

term.

Discharge of 

chlorine or other 

biocides

Generic SMALL. Effects are not a concern among regulatory and 

resource agencies, and are not expected to be a problem 

during the license renewal term.
Appendix B

B-2

Issue Type of Issue Finding

Discharge of 

sanitary wastes and 

minor chemical 

spills

Generic SMALL. Effects are readily controlled through NPDES

permit and periodic modifications, if needed, and are not 

expected to be a problem during the license renewal 

term.

Discharge of other 

metals in 

wastewater

Generic SMALL. These discharges have not been found to be a 

problem at operating nuclear power plants with coolingtower-based heat dissipation systems and have been 

satisfactorily mitigated at other plants. They are not 

expected to be a problem during the license renewal 

term.

Water use conflicts 

(plants with oncethrough cooling 

systems)

Generic SMALL. These conflicts have not been found to be a 

problem at operating nuclear power plants with oncethrough heat dissipation systems.

Water use conflicts 

(plants with cooling 

ponds or cooling 

towers using makeup water from a 

small river with low 

flow)

Site-specific SMALL OR MODERATE. The issue has been a concern 

at nuclear power plants with cooling ponds and at plants 

with cooling towers. Impacts on instream and riparian 

communities near these plants could be of moderate 

significance in some situations. See § 51.53(c)(3)(ii)(A).

Aquatic Ecology

Refurbishment Generic SMALL. During plant shutdown and refurbishment there 

will be negligible effects on aquatic biota because of a 

reduction of entrainment and impingement of organisms 

or a reduced release of chemicals.

Accumulation of 

contaminants in 

sediments or biota

Generic SMALL. Accumulation of contaminants has been a 

concern at a few nuclear power plants but has been 

satisfactorily mitigated by replacing copper alloy 

condenser tubes with those of another metal. It is not 

expected to be a problem during the license renewal 

term.

Entrainment of 

phytoplankton and 

zooplankton

Generic SMALL. Entrainment of phytoplankton and zooplankton 

has not been found to be a problem at operating nuclear 

power plants and is not expected to be a problem during 

the license renewal term.

Cold shock Generic SMALL. Cold shock has been satisfactorily mitigated at 

operating nuclear plants with once-through cooling 

systems, has not endangered fish populations or been 

found to be a problem at operating nuclear power plants 

with cooling towers or cooling ponds, and is not expected 

to be a problem during the license renewal term.

Thermal plume 

barrier to migrating 

fish

Generic SMALL. Thermal plumes have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term.
Appendix B

B-3

Issue Type of Issue Finding

Distribution of 

aquatic organisms

Generic SMALL. Thermal discharge may have localized effects 

but is not expected to affect the larger geographical 

distribution of aquatic organisms.

Premature 

emergence of 

aquatic insects

Generic SMALL. Premature emergence has been found to be a 

localized effect at some operating nuclear power plants 

but has not been a problem and is not expected to be a 

problem during the license renewal term.

Gas 

supersaturation 

(gas bubble 

disease)

Generic SMALL. Gas supersaturation was a concern at a small 

number of operating nuclear power plants with oncethrough cooling systems but has been satisfactorily 

mitigated. It has not been found to be a problem at 

operating nuclear power plants with cooling towers or 

cooling ponds and is not expected to be a problem during 

the license renewal term.

Low dissolved 

oxygen in the 

discharge

Generic SMALL. Low dissolved oxygen has been a concern at 

one nuclear power plant with a once-through cooling 

system but has been effectively mitigated. It has not been 

found to be a problem at operating nuclear power plants 

with cooling towers or cooling ponds and is not expected 

to be a problem during the license renewal term.

Losses from 

predation, 

parasitism, and 

disease among 

organisms exposed 

to sublethal 

stresses

Generic SMALL. These types of losses have not been found to be 

a problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term.

Stimulation of 

nuisance organisms 

(e.g., shipworms)

Generic SMALL. Stimulation of nuisance organisms has been 

satisfactorily mitigated at the single nuclear power plant 

with a once-through cooling system where previously it 

was a problem. It has not been found to be a problem at 

operating nuclear power plants with cooling towers or 

cooling ponds and is not expected to be a problem during 

the license renewal term.

Aquatic Ecology (for plants with once-through and cooling pond heat dissipation systems)

Entrainment of fish 

and shellfish in 

early life stages

Site-specific SMALL, MODERATE, OR LARGE. The impacts of 

entrainment are small at many plants but may be 

moderate or even large at a few plants with once-through 

and cooling-pond cooling systems. Further, ongoing 

efforts in the vicinity of these plants to restore fish 

populations may increase the numbers of fish susceptible 

to intake effects during the license renewal period, such 

that entrainment studies conducted in support of the 

original license may no longer be valid. See § 

51.53(c)(3)(ii)(B).
Appendix B

B-4

Issue Type of Issue Finding

Impingement of fish 

and shellfish

Site-specific SMALL, MODERATE, OR LARGE. The impacts of 

impingement are small at many plants but may be 

moderate or even large at a few plants with once-through 

and cooling-pond cooling systems. See § 

51.53(c)(3)(ii)(B).

Heat shock Site-specific SMALL, MODERATE, OR LARGE. Because of 

continuing concerns about heat shock and the possible 

need to modify thermal discharges in response to 

changing environmental conditions, the impacts may be 

of moderate or large significance at some plants. See § 

51.53(c)(3)(ii)(B).

Aquatic Ecology (for plants with cooling-tower-based heat dissipation systems)

Entrainment of fish 

and shellfish in 

early life stages

Generic SMALL. Entrainment of fish has not been found to be a 

problem at operating nuclear power plants with this type 

of cooling system and is not expected to be a problem 

during the license renewal term.

Impingement of fish 

and shellfish

Generic SMALL. The impingement has not been found to be a 

problem at operating nuclear power plants with this type 

of cooling system and is not expected to be a problem 

during the license renewal term.

Heat shock Generic SMALL. Heat shock has not been found to be a problem 

at operating nuclear power plants with this type of cooling

system and is not expected to be a problem during the 

license renewal term.

Ground Water Use and Quality

Impacts of 

refurbishment on 

ground water use 

and quality

Generic SMALL. Extensive dewatering during the original 

construction on some sites will not be repeated during 

refurbishment on any sites. Any plant wastes produced 

during refurbishment will be handled in the same manner 

as in current operating practices and are not expected to 

be a problem during the license renewal term.

Ground water use 

conflicts (potable 

and service water; 

plants that use 

<100 gpm)

Generic SMALL. Plants using less than 100 gpm are not expected 

to cause any ground water use conflicts.

Ground water use 

conflicts (potable 

and service water, 

and dewatering 

plants that use 

>100 gpm)

Site-specific SMALL, MODERATE, OR LARGE. Plants that use more 

than 100 gpm may cause ground water use conflicts with 

nearby ground water users. See § 51.53(c)(3)(ii)(C).

Ground water use 

conflicts (plants 

using cooling 

towers withdrawing 

make-up water from 

a small river)

Site-specific SMALL, MODERATE, OR LARGE. Water use conflicts 

may result from surface water withdrawals from small 

water bodies during low flow conditions which may affect 

aquifer recharge, especially if other ground water or 

upstream surface water users come on line before the 

time of license renewal. See § 51.53(c)(3)(ii)(A).
Appendix B

B-5

Issue Type of Issue Finding

Ground water use 

conflicts (Ranney 

wells)

Site-specific SMALL, MODERATE, OR LARGE. Ranney wells can 

result in potential ground water depression beyond the 

site boundary. Impacts of large ground water withdrawal 

for cooling tower makeup at nuclear power plants using 

Ranney wells must be evaluated at the time of application 

for license renewal. See § 51.53(c)(3)(ii)(C).

Ground water 

quality degradation 

(Ranney wells)

Generic SMALL. Ground water quality at river sites may be 

degraded by induced infiltration of poor-quality river water 

into an aquifer that supplies large quantities of reactor

cooling water. However, the lower quality infiltrating water 

would not preclude the current uses of ground water and 

is not expected to be a problem during the license 

renewal term.

Ground water 

quality degradation 

(saltwater intrusion)

Generic SMALL. Nuclear power plants do not contribute 

significantly to saltwater intrusion.

Ground water 

quality degradation 

(cooling ponds in 

salt marshes)

Generic SMALL. Sites with closed-cycle cooling ponds may 

degrade ground water quality. Because water in salt 

marshes is brackish, this is not a concern for plants 

located in salt marshes.

Ground water 

quality degradation 

(cooling ponds at 

inland sites)

Site-specific SMALL, MODERATE, OR LARGE. Sites with closedcycle cooling ponds may degrade ground water quality. 

For plants located inland, the quality of the ground water 

in the vicinity of the ponds must be shown to be adequate 

to allow continuation of current uses. See § 

51.53(c)(3)(ii)(D).

Terrestrial Ecology

Refurbishment 

impacts

Site-specific SMALL, MODERATE, OR LARGE. Refurbishment 

impacts are insignificant if no loss of important plant and 

animal habitat occurs. However, it cannot be known 

whether important plant and animal communities may be 

affected until the specific proposal is presented with the 

license renewal application. See § 51.53(c)(3)(ii)(E).

Cooling tower 

impacts on crops 

and ornamental 

vegetation

Generic SMALL. Impacts from salt drift, icing, fogging, or 

increased humidity associated with cooling tower 

operation have not been found to be a problem at 

operating nuclear power plants and are not expected to 

be a problem during the license renewal term.

Cooling tower 

impacts on native 

plants

Generic SMALL. Impacts from salt drift, icing, fogging, or 

increased humidity associated with cooling tower 

operation have not been found to be a problem at 

operating nuclear power plants and are not expected to 

be a problem during the license renewal term.

Bird collisions with 

cooling towers

Generic SMALL. These collisions have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term.
Appendix B

B-6

Issue Type of Issue Finding

Cooling pond 

impacts on 

terrestrial resources

Generic SMALL. Impacts of cooling ponds on terrestrial ecological 

resources are considered to be of small significance at all 

sites.

Power line right of 

way management 

(cutting and 

herbicide 

application)

Generic SMALL. The impacts of right-of-way maintenance on 

wildlife are expected to be of small significance at all 

sites.

Bird collisions with 

power lines

Generic SMALL. Impacts are expected to be of small significance 

at all sites.

Impacts of 

electromagnetic 

fields on flora and 

fauna

Generic SMALL. No significant impacts of electromagnetic fields

on terrestrial flora and fauna have been identified. Such 

effects are not expected to be a problem during the 

license renewal term.

Floodplains and 

wetland on power 

line right of way

Generic SMALL. Periodic vegetation control is necessary in 

forested wetlands underneath power lines and can be 

achieved with minimal damage to the wetland. No 

significant impact is expected at any nuclear power plant 

during the license renewal term.

Threatened and Endangered Species

Threatened or 

endangered

species

Site-specific SMALL, MODERATE, OR LARGE. Generally, plant 

refurbishment and continued operation are not expected 

to adversely affect threatened or endangered species. 

However, consultation with appropriate agencies would 

be needed at the time of license renewal to determine 

whether threatened or endangered species are present 

and whether they would be adversely affected. See § 

51.53(c)(3)(ii)(E).

Air Quality

Air quality during 

refurbishment (nonattainment and 

maintenance areas)

Site-specific SMALL, MODERATE, OR LARGE. Air quality impacts 

from plant refurbishment associated with license renewal 

are expected to be small. However, vehicle exhaust 

emissions could be cause for concern at locations in or 

near nonattainment or maintenance areas. The 

significance of the potential impact cannot be determined 

without considering the compliance status of each site 

and the numbers of workers expected to be employed 

during the outage. See § 51.53(c)(3)(ii)(F).

Air quality effects of 

transmission lines

Generic SMALL. Production of ozone and oxides of nitrogen is 

insignificant and does not contribute measurably to 

ambient levels of these gases.

Land Use

Onsite land use Generic SMALL. Projected onsite land use changes required 

during refurbishment and the renewal period would be a 

small fraction of any nuclear power plant site and would 

involve land that is controlled by the applicant.
Appendix B

B-7

Issue Type of Issue Finding

Power line right of 

way

Generic SMALL. Ongoing use of power line right of ways would 

continue with no change in restrictions. The effects of 

these restrictions are of small significance.

Human Health

Radiation 

exposures to the

public during 

refurbishment

Generic SMALL. During refurbishment, the gaseous effluents 

would result in doses that are similar to those from 

current operation. Applicable regulatory dose limits to the 

public are not expected to be exceeded.

Occupational 

radiation exposures 

during 

refurbishment

Generic SMALL. Occupational doses from refurbishment are 

expected to be within the range of annual average 

collective doses experienced for pressurized-water 

reactors and boiling-water reactors. Occupational 

mortality risk from all causes including radiation is in the 

mid-range for industrial settings.

Microbiological 

organisms 

(occupational 

health)

Generic SMALL. Occupational health impacts are expected to be 

controlled by continued application of accepted industrial 

hygiene practices to minimize worker exposures.

Microbiological 

organisms (public 

health)(plants using 

lakes or canals, or 

cooling towers or 

cooling ponds that 

discharge to a small 

river)

Site-specific SMALL, MODERATE, OR LARGE. These organisms are 

not expected to be a problem at most operating plants 

except possibly at plants using cooling ponds, lakes, or 

canals that discharge to small rivers. Without site-specific 

data, it is not possible to predict the effects generically. 

See § 51.53(c)(3)(ii)(G).

Noise Generic SMALL. Noise has not been found to be a problem at 

operating plants and is not expected to be a problem at 

any plant during the license renewal term.

Electromagnetic 

fields – acute 

effects (electric 

shock)

Site-specific SMALL, MODERATE, OR LARGE. Electrical shock 

resulting from direct access to energized conductors or 

from induced charges in metallic structures have not 

been found to be a problem at most operating plants and 

generally are not expected to be a problem during the 

license renewal term. However, site-specific review is 

required to determine the significance of the electric 

shock potential at the site. See § 51.53(c)(3)(ii)(H).

Electromagnetic 

fields – chronic 

effects

Uncategorized UNCERTAIN. Biological and physical studies of 60-Hz 

electromagnetic fields have not found consistent 

evidence linking harmful effects with field exposures. 

However, research is continuing in this area and a 

consensus scientific view has not been reached. 

Radiation 

exposures to public 

(license renewal 

term)

Generic SMALL. Radiation doses to the public will continue at 

current levels associated with normal operations.
Appendix B

B-8

Issue Type of Issue Finding

Occupational 

radiation exposures 

(license renewal 

term)

Generic SMALL. Projected maximum occupational doses during 

the license renewal term are within the range of doses 

experienced during normal operations and normal 

maintenance outages, and would be well below 

regulatory limits.

Socioeconomic Impacts

Housing impacts Site-specific SMALL, MODERATE, OR LARGE. Housing impacts are 

expected to be of small significance at plants located in a 

medium or high population area and not in an area where 

growth control measures that limit housing development 

are in effect. Moderate or large housing impacts of the 

workforce associated with refurbishment may be 

associated with plants located in sparsely populated 

areas or in areas with growth control measures that limit 

housing development. See § 51.53(c)(3)(ii)(I).

Public services: 

public safety, social 

services, and 

tourism, and 

recreation

Generic SMALL. Impacts to public safety, social services, and 

tourism and recreation are expected to be of small 

significance at all sites.

Public services: 

public utilities

Site-specific SMALL OR MODERATE. An increased problem with 

water shortages at some sites may lead to impacts of 

moderate significance on public water supply availability. 

See § 51.53(c)(3)(ii)(I).

Public services: 

education

(refurbishment)

Site-specific SMALL, MODERATE, OR LARGE. Most sites would 

experience impacts of small significance but larger 

impacts are possible depending on site- and projectspecific factors. See § 51.53(c)(3)(ii)(I).

Public services: 

education (license 

renewal term)

Generic SMALL. Only impacts of small significance are expected

Offsite land use 

(refurbishment)

Site-specific SMALL OR MODERATE. Impacts may be of moderate 

significance at plants in low population areas. See § 

51.53(c)(3)(ii)(I).

Offsite land use 

(license renewal 

term)

Site-specific SMALL, MODERATE, OR LARGE. Significant changes in 

land use may be associated with population and tax 

revenue changes resulting from license renewal. See § 

51.53(c)(3)(ii)(I).

Public services: 

transportation

Site-specific SMALL, MODERATE, OR LARGE. Transportation 

impacts (level of service) of highway traffic generated 

during plant refurbishment and during the term of the 

renewed license are generally expected to be of small 

significance. However, the increase in traffic associated 

with the additional workers and the local road and traffic 

control conditions may lead to impacts of moderate or 

large significance at some sites. See § 51.53(c)(3)(ii)(J).
Appendix B

B-9

Issue Type of Issue Finding

Historic and 

archaeological 

resources

Site-specific SMALL, MODERATE, OR LARGE. Generally, plant 

refurbishment and continued operation are expected to 

have no more than small adverse impacts on historic and 

archaeological resources. However, the National Historic 

Preservation Act requires the Federal agency to consult 

with the State Historic Preservation Officer to determine 

whether there are properties present that require 

protection. See § 51.53(c)(3)(ii)(K).

Aesthetic impacts 

(refurbishment)

Generic SMALL. No significant impacts are expected during 

refurbishment.

Aesthetic impacts 

(license renewal 

term)

Generic SMALL. No significant impacts are expected during the 

license renewal term.

Aesthetic impacts of 

transmission lines

(license renewal 

term)

Generic SMALL. No significant impacts are expected during the 

license renewal term.

Postulated Accidents

Design basis 

accidents

Generic SMALL. The NRC staff has concluded that the 

environmental impacts of design basis accidents are of 

small significance for all plants.

Severe accidents Site-specific SMALL. The probability weighted consequences of 

atmospheric releases, fallout onto open bodies of water, 

releases to ground water, and societal and economic 

impacts from severe accidents are small for all plants. 

However, alternatives to mitigate severe accidents must 

be considered for all plants that have not considered such 

alternatives. See § 51.53(c)(3)(ii)(L).

Uranium Fuel Cycle and Waste Management

Offsite radiological 

impacts (individual 

effects from other 

than the disposal of 

spent fuel and high 

level waste)

Generic SMALL. Offsite impacts of the uranium fuel cycle have 

been considered by the Commission in Table S-3 of this 

part. Based on information in the GEIS, impacts on 

individuals from radioactive gaseous and liquid releases 

including radon-222 and technetium-99 are small.
Appendix B

B-10

Issue Type of Issue Finding

Offsite radiological 

impacts (collective 

effects)

Generic The 100 year environmental dose commitment to the 

U.S. population from the fuel cycle, high level waste and 

spent fuel disposal excepted, is calculated to be about 

14,800 person rem, or 12 cancer fatalities, for each 

additional 20-year power reactor operating term. Much of 

this, especially the contribution of radon releases from 

mines and tailing piles, consists of tiny doses summed 

over large populations. This same dose calculation can 

theoretically be extended to include many tiny doses over 

additional thousands of years as well as doses outside 

the U. S. The result of such a calculation would be 

thousands of cancer fatalities from the fuel cycle, but this 

result assumes that even tiny doses have some statistical 

adverse health effect which will not ever be mitigated (for 

example no cancer cure in the next thousand years), and 

that these doses projected over thousands of years are 

meaningful. However, these assumptions are 

questionable. In particular, science cannot rule out the 

possibility that there will be no cancer fatalities from these 

tiny doses. For perspective, the doses are very small 

fractions of regulatory limits, and even smaller fractions of 

natural background exposure to the same populations. 

Nevertheless, despite all the uncertainty, some judgment 

as to the regulatory NEPA implications of these matters 

should be made and it makes no sense to repeat the 

same judgment in every case. Even taking the 

uncertainties into account, the Commission concludes 

that these impacts are acceptable in that these impacts 

would not be sufficiently large to require the NEPA 

conclusion, for any plant, that the option of extended 

operation under 10 CFR Part 54 should be eliminated. 

Accordingly, while the commission has not assigned a 

single level of significance for the collective effects of the 

fuel cycle, this issue is considered Category 1 [Generic].
Appendix B

B-11

Issue Type of Issue Finding

Offsite radiological 

impacts (spent fuel

and high level 

waste disposal)

Generic For the high level waste and spent fuel disposal 

component of the fuel cycle, there are no current 

regulatory limits for offsite releases of radionuclides for 

the current candidate repository site. However, if we 

assume that limits are developed along the lines of the 

1995 National Academy of Sciences (NAS) report, 

"Technical Bases for Yucca Mountain Standards," and 

that in accordance with the Commission's Waste 

Confidence Decision, 10 CFR 51.23, a repository can and 

likely will be developed at some site which will comply 

with such limits, peak doses to virtually all individuals will 

be 100 millirem per year or less. However, while the 

Commission has reasonable confidence that these 

assumptions will prove correct, there is considerable 

uncertainty since the limits are yet to be developed, no 

repository application has been completed or reviewed, 

and uncertainty is inherent in the models used to evaluate 

possible pathways to the human environment. The NAS 

report indicated that 100 millirem per year should be 

considered as a starting point for limits for individual 

doses, but notes that some measure of consensus exists 

among national and international bodies that the limits 

should be a fraction of the 100 millirem per year. The 

lifetime individual risk from 100 millirem annual dose limit 

is about 3 x 10-3.

Estimating cumulative doses to populations over 

thousands of years is more problematic. The likelihood 

and consequences of events that could seriously 

compromise the integrity of a deep geologic repository 

were evaluated by the Department of Energy in the "Final 

Environmental Impact Statement: Management of 

Commercially Generated Radioactive Waste," October 

1980. The evaluation estimated the 70-year whole-body 

dose commitment to the maximum individual and to the 

regional population resulting from several modes of 

breaching a reference repository in the year of closure, 

after 1,000 years, after 100,000 years and after 

100,000,000 years.
Appendix B

B-12

Issue Type of Issue Finding

Subsequently, the NRC and other federal agencies have 

expended considerable effort to develop models for the 

design and for the licensing of a high level waste

repository, especially for the candidate repository at 

Yucca Mountain. More meaningful estimates of doses to 

population may be possible in the future as more is 

understood about the performance of the proposed 

Yucca Mountain repository. Such estimates would involve 

very great uncertainty, especially with respect to 

cumulative population doses over thousands of years. 

The standard proposed by the NAS is a limit on maximum 

individual dose. The relationship of potential new 

regulatory requirements, based on the NAS report, and 

cumulative population impacts has not been determined, 

although the report articulates the view that protection of 

individuals will adequately protect the population for a 

repository at Yucca Mountain. However, EPA's generic 

repository standards in 40 CFR Part 191 generally 

provide an indication of the order of magnitude of 

cumulative risk to population that could result from the 

licensing of a Yucca Mountain repository, assuming the 

ultimate standards will be within the range of standards 

now under consideration. The standards in 40 CFR Part 

191 protect the population by imposing amount of 

radioactive material released over 10,000 years. The 

cumulative release limits are based on EPA's population 

impact goal of 1,000 premature cancer deaths worldwide 

for a 100,000 metric ton (MTHM) repository.

Nevertheless, despite all the uncertainty, some judgment 

as to the regulatory NEPA implications of these matters 

should be made and it makes no sense to repeat the 

same judgment in every case. Even taking the 

uncertainties into account, the Commission concludes 

that these impacts are acceptable in that these impacts 

would not be sufficiently large to require the NEPA 

conclusion, for any plant, that the option of extended 

operation under 10 CFR Part 54 should be eliminated. 

Accordingly, while the Commission has not assigned a 

single level of significance for the impacts of spent fuel

and high level waste disposal, this issue is considered in 

Category 1 [Generic].

Nonradiological 

impacts of the 

uranium fuel cycle

Generic SMALL. The nonradiological impacts of the uranium fuel 

cycle resulting from the renewal of an operating license 

for any plant are found to be small.

Decommissioning

Radiation doses Generic SMALL. Doses to the public will be well below applicable 

regulatory standards regardless of which 

decommissioning method is used. Occupational doses 

would increase no more than 1 man-rem caused by 

buildup of long-lived radionuclides during the license 

renewal term.
Appendix B

B-13

Issue Type of Issue Finding

Waste management Generic SMALL. Decommissioning at the end of a 20-year license 

renewal period would generate no more solid wastes than 

at the end of the current license term. No increase in the 

quantities of Class C or greater than Class C wastes 

would be expected.

Air quality Generic SMALL. Air quality impacts of decommissioning are 

expected to be negligible either at the end of the current 

operating term or at the end of the license renewal term.

Water quality Generic SMALL. The potential for significant water quality impacts 

from erosion or spills is no greater whether 

decommissioning occurs after a 20-year license renewal 

period or after the original 40-year operation period, and 

measures are readily available to avoid such impacts.

Ecological 

resources

Generic SMALL. Decommissioning after either the initial operating 

period or after a 20-year license renewal period is not 

expected to have any direct ecological impacts.

Socioeconomic 

impacts

Generic SMALL. Decommissioning would have some short-term 

socioeconomic impacts. The impacts would not be 

increased by delaying decommissioning until the end of a 

20-year relicense period, but they might be decreased by 

population and economic growth.

Environmental Justice

Environmental 

Justice

Uncategorized NONE. The need for and the content of an analysis of 

environmental justice will be addressed in plant-specific 

reviews.


APPENDIX C

APPLICABLE REGULATIONS, LAWS, AND AGREEMENT


C-1

C. Applicable Regulations, Laws, and Agreements

The Atomic Energy Act of 1954 (AEA) authorizes States to establish programs to assume NRC 

regulatory authority for certain activities. For example, through section 274b of the AEA, as 

amended, beginning on January 13, 2006, Minnesota assumed regulatory authority for: (1) 

byproduct materials as defined in 11e.(1) of the Act; (2) source materials; and (3) special 

nuclear materials in quantities not sufficient to form a critical mass. The Minnesota Radiation 

Control Unit (RCU) is responsible for implementing State nuclear regulations. Minnesota did not 

seek authority to: (a) conduct safety evaluations of sealed sources and devices manufactured in 

Minnesota and distributed in interstate commerce; (b) regulate the disposal of low-level 

radioactive waste at a land disposal site as described in 10 CFR Part 61; or (c) regulate 11e.(2) 

byproduct material resulting from the extraction or concentration of source material from ore 

processed primarily for its source material content, and its management and disposal. 

In addition to implementing some Federal programs, State legislatures develop their own laws. 

State statutes supplement as well as implement Federal laws for protection of air, water quality, 

and ground water. State legislation may address solid waste management programs, locally 

rare or endangered species, and historic and cultural resources.

The Clean Water Act (CWA) allows for primary enforcement and administration through State 

agencies, provided the State program is at least as stringent as the Federal program. The State 

program must conform to the CWA and to the delegation of authority for the Federal National 

Pollutant Discharge and Elimination System (NPDES) program from the U.S. Environmental 

Protection Agency (EPA) to the State. The primary mechanism to control water pollution is the 

requirement for direct dischargers to obtain an NPDES permit. In Minnesota, the Minnesota 

Pollution Control Agency (MPCA) issues and enforces NPDES permits.

One important difference between Federal regulations and certain State regulations is the 

definition of waters regulated by the State. Certain state regulations may include underground 

waters, while the CWA only regulates surface waters. 

C.1. State Environmental Requirements

Certain environmental requirements, including some discussed earlier, may have been 

delegated to State authorities for implementation, enforcement, or oversight. Table C-1 provides 

a list of representative State environmental requirements that may affect license renewal 

applications for nuclear power plants.
Appendix C

C-2

Table C-1. State Environmental Requirements. PINGP 1 and 2 are subject to 

numerous State requirements regarding their environmental program. Those 

requirements are briefly described below. See Section 1.9 for PINGP 1 and 

2’s compliance status with these requirements.

Law/Regulation Requirements

Air Quality Protection

Air Pollution Control Act, 

Minnesota Administrative Rules 

and Laws, Chapter 7007, Air 

Emission Permits, Section 1450

All emission sources at PINGP 1 and 2, must obtain a Synthetic 

Minor Operating Permit prior to operation; the MPCA issues and 

enforces permits. PINGP holds a Title V permit, which authorizes the 

installation and operation of all emission sources at the site. MPCA 

does not require an amendment to the permit prior to installation.

Water Resources Protection

Clean Water Act (CWA) (33 

U.S.C. Section 1251 et seq.); 

Minnesota Stat. § 115.03, subd. 

1(e)(10) “Requiring that 

applicants for wastewater 

discharge permits evaluate in 

their applications the potential 

reuses of the discharged 

wastewater.”

The NPDES permit is required for plant industrial, sanitary, and 

stormwater discharges to the Mississippi River. The NPDES permit 

requires the compliance of each point source with authorized 

discharge levels, monitoring requirements, and other appropriate 

requirements. The MPCA is the responsible State agency for 

NPDES permitting.

CWA (33 U.S.C. Section 401) The CWA Section 401 Water Quality Certification requires a Section 

401 water quality certification and payment of applicable fees before 

the issuance of a Federal permit or license to conduct any activity 

that may result in any discharge to waters of the State. In Minnesota, 

State issuance of an NPDES permit constitutes 401 Certification.

2008 Minnesota State Statutes 

103G.265, Laws regarding Water 

Supply Management

Subd. 3. requires a permit to cover consumptive water use over 

2,000,000 gallons per day (gpd) (over a 30-day average) of surface 

and ground water; the Minnesota Department of Natural Resources 

(MNDNR) is the regulatory agency that issues and enforces 

consumptive water use permits.

2008 Minnesota State Statutes 

103G.265, Laws regarding Water 

Supply Management

Subd. 3. requires a permit to cover ground water withdrawals over

100,000 gpd or more (over a 30-day average) of surface water, 

ground water, or a combination of the two; the MNDNR is the 

regulatory agency that issues and enforces ground water withdrawal 

permits.

Minnesota State Statutes 

103G.127 Permit Program

The U.S. Army Corps of Engineers in cooperation with MNDNR 

issues maintenance dredging permits for maintenance dredging of 

the area around PINGP 1 and 2.

Minnesota State Statutes 

103G.127 Permit Program

Maintenance dredging of the PIINGP, Units 1 and 2 intake canal in 

the Mississippi River also requires a maintenance dredging permit 

issued by the MNDNR.

Minnesota Safe Drinking Water 

Act (40 CFR 141 and 142); 2008 

Minnesota Statutes 103G.291 

Public Water Supply Plans; 

Appropriation During Deficiency.

The MNDNR issues and enforces public water supply permits for 

operation of the PINGP 1 and 2, plant site drinking water systems.
Appendix C

C-3

Law/Regulation Requirements

Minnesota 2008 State Statutes 

282.0195 Subd. 2. Storage tank 

sites for state laws and 

regulations; Chapter 7150 

Minnesota Pollution Control 

Agency Underground Storage 

Tanks Program for state 

permitting and registration 

requirements.

The State of Minnesota issues storage tank registration and permit 

certificates, which establish annual registration requirements for 

underground storage tanks containing petroleum or other regulated 

substances. The MPCA, Industrial Division is the State contact for 

obtaining permits, as well as issuing any fines and/or performance 

measures.

Minnesota 2008 State Statute 

7150.0100 Performance 

standards for underground 

storage tank systems; Minnesota 

2008 State Statute 7150.0215 

Operation and Maintenance of 

Cathodic Protection.

These laws regulate flammable and combustible liquid storage tanks 

as well as the approval to construct or operate an underground 

storage tank containing flammable or combustible liquids.

Minnesota 2008 State Statute 

458D.07 Sewage Collection and 

Disposal; 2008 State Statute 

458D.07 Subd. 6. deals 

specifically with discharge of 

treated sewage.

The State of Minnesota and the MPCA issues sewage sludge 

disposal agreements, which are required for the disposal of sewage 

sludge. The MPCA also issues on-lot sewage disposal system 

permits, and permit modifications for approvals of additional flows to 

on-lot sewage treatment systems.
Appendix C

C-4

C.2. Operating Permits and Other Requirements

Several operating permit applications may be prepared and submitted, and regulator approval 

and permits would be received prior to license renewal approval by the NRC. Table C-2 lists 

representative Federal, State, and local permits.

Table C-2. Federal, State, and Local Permits and Other Requirements. PINGP 1 and 

2, is subject to other requirements regarding various aspects of their 

environmental program. Those requirements are briefly described below.

License, Permit, or Other 

Required Approval

Responsible 

Agency Authority Relevance and Status

Air Quality Protection

Approval (operating permit) 

for construction or 

modification of an air 

pollutant source.

MPCA Clean Air Act, Title V, 

Sections 501-507 (42 

U.S.C. 7661-7661f);

Minn. Stat. § 116.07

MPCA does not require an 

amendment to the permit for 

temporary emissions, such as 

those associated with 

refurbishment.

Water Resources Protection

NPDES permit for 

construction site storm water 

and other project-specific 

discharges.

MPCA CWA (33 U.S.C. 1251 

et seq.); 40 CFR Part 

122; Minn Stat. § 7090

NSP may need to modify the 

existing PINGP 1 and 2

NPDES permit, or otherwise 

obtain authorization for 

temporary discharges 

associated with refurbishment.

Review and approval of any 

project that will result in 

consumptive use of water 

from the Mississippi River 

within the State of 

Minnesota.

MNDNR 2008 Minnesota 

Statutes 103G.265 

Water Supply 

Management.

Modifications to the existing 

PINGP 1 and 2 consumptive 

water use permit may be 

necessary to supply water for 

refurbishment activities. 

Appropriations permit 

required for any user 

withdrawing more than 

10,000 gpd or 1 million 

gallons of per year.

MNDNR Minn Stat. § 103G.271 Refurbishment activities at 

PINGP 1 and 2 may require 

additional water withdrawal or 

an increased pumping rate; the 

existing PINGP 1 and 2

surface and/or groundwater 

appropriation permit(s) may 

require modification.

Permit required before 

construction, modification, 

removal, destruction, or 

abandonment of an 

obstruction in a floodplain.

MNDNR “The Flood Plain 

Management Law;” 

Minnesota Statute 

103F.101 – 103F.

NSP is reviewing flood plain 

elevations associated with 

refurbishment activities; if 

avoidance is not possible, NSP 

may be required to apply for 

appropriate permits.
Appendix C

C-5

License, Permit, or Other 

Required Approval

Responsible 

Agency Authority Relevance and Status

A Spill Prevention Control 

and Countermeasures 

(SPCC) Plan is required for 

any facility that could 

discharge diesel fuel in 

harmful quantities into 

navigable waters or onto 

adjoining shorelines.

MNDNR and 

EPA Region 5

CWA (33 U.S.C. 1251 

et seq.); 40 CFR Part 

112; 

A SPCC Plan is required at 

nuclear power plants storing 

large volumes of diesel fuel or 

other petroleum products. NSP 

may need to modify its existing 

SPCC Plan, or develop a new 

plan to cover activities 

associated with refurbishment. 

New Underground Storage 

Tanks System Registration 

is required within 30 days of 

bringing a new underground 

storage tank system into 

service.

MPCA Resource 

Conservation and 

Recovery Act (RCRA), 

as amended, Subtitle I 

(42 U.S.C. 6991a6991i); 40 CFR 

§280.22; Storage 

Tank and Spill 

Prevention (35 P.S. 

6021.101-6021.2104); 

Minnesota 2008 State 

Statutes 7150.0100 –

7150.0210

Required if new underground 

storage tank systems would be 

installed during refurbishment.

Waste Management and Pollution Prevention

Registration and Hazardous 

Waste Generator 

Identification Number are 

required before a facility that 

generates over 100 kg (220 

lb) per calendar month of 

hazardous waste ships the 

hazardous waste offsite.

MPCA and 

EPA Region 5

RCRA, as amended 

(42 U.S.C. 6901 et 

seq.), Subtitle C; 

Minnesota State 

Statute 7045.0125 

Hazardous Waste 

Generator’s License

Generators of hazardous 

waste must notify EPA that the 

wastes exist and require 

management in compliance 

with RCRA. NSP is required to 

characterize wastes generated 

by refurbishment to determine 

proper disposal procedures 

and permit requirements.

Emergency Planning and Response

Submission of a list of 

Material Safety Data Sheets 

is required for hazardous 

chemicals (as defined in 29 

CFR Part 1910) that are 

stored onsite in excess of 

their threshold quantities.

State and 

local 

emergency 

planning 

agencies

Emergency Planning 

and Community Rightto-Know Act of 1986 

(EPCRA), Section 311 

(42 U.S.C. 11021); 40 

CFR §370.20

Nuclear power plant operators 

are required to submit a List of 

Material Safety Data Sheets to 

State and local emergency 

planning agencies.

Transportation of 

Radioactive Wastes and 

Conversion Products 

Packaging, Labeling, and 

Routing Requirements for 

Radioactive Materials is 

required for packages 

containing radioactive 

materials that will be shipped 

by truck or rail.

U.S. 

Department of 

Transportation

HMTA (49 U.S.C. 

1501 et seq.); Atomic 

Energy Act (AEA), as 

amended (42 U.S.C. 

2011 et seq.); 49 CFR 

Parts 172, 173, 174, 

177, and 397

When shipments of radioactive 

materials are made, nuclear 

power plant operators are 

required to comply with U.S. 

Department of Transportation 

packaging, labeling, and 

routing requirements.
Appendix C

C-6

License, Permit, or Other 

Required Approval

Responsible 

Agency Authority Relevance and Status

Biotic Resource Protection

Threatened and Endangered 

Species Consultation is 

required between the 

responsible Federal 

agencies and affected States 

to ensure that the project is 

not likely to: (1) jeopardize 

the continued existence of 

any species listed at the 

Federal or State level as 

endangered or threatened; 

or (2) result in destruction of 

critical habitat of such 

species.

U.S. Fish and 

Wildlife 

Service (FWS)

and State 

agencies

Endangered Species 

Act of 1973, as 

amended (16 U.S.C. 

1531 et seq.)

NRC will consult with FWS and 

State agencies regarding the 

impact of license renewal on 

threatened or endangered 

species or their critical 

habitats.

CWA Section 404 (Dredge 

and Fill) Permit is required to 

place dredged or fill material 

into waters of the U.S., 

including areas designated 

as wetlands, unless such 

placement is exempt or 

authorized by a nationwide 

permit or a regional permit; a 

notice must be filed if a 

nationwide or regional permit 

applies.

U.S. Army 

Corps of 

Engineers

CWA (33 U.S.C. 1251 

et seq.); 33 CFR Parts 

323 and 330

Any dredging or placement of 

fill material at a nuclear power 

plant into wetlands within the 

jurisdiction of the U.S. Army 

Corps of Engineers would 

require a Section 404 permit.

Cultural Resources Protection

Archaeological and Historical 

Resources Consultation is 

required before a Federal 

agency approves a project in 

an area where 

archaeological or historic 

resources might be located.

Minnesota 

Office of the 

State 

Archeologist

National Historic 

Preservation Act of 

1966, as amended (16 

U.S.C. 470 et seq.); 

Archaeological and 

Historical Preservation 

Act of 1974 (16 U.S.C. 

469-469c-2); 

Antiquities Act of 1906 

(16 U.S.C. 431 et 

seq.); Archaeological 

Resources Protection 

Act of 1979, as 

amended (16 U.S.C. 

470aa-mm)

NRC will consult with the State 

and Tribal Historic 

Preservation Officers and 

representative Indian tribes 

regarding the impacts of 

license renewal and the results 

of archaeological and 

architectural surveys of 

nuclear power plant sites.
1 APPENDIX D

2

3

4

5 CONSULTATION CORRESPONDENCE

6

D-1

D. Consultation Correspondence

The Endangered Species Act of 1973, as amended, the Magnuson-Stevens Fisheries 

Management Act of 1996, as amended; and the National Historic Preservation Act of 1966 

require that Federal agencies consult with applicable State and Federal agencies and groups 

prior to taking action that may affect threatened and endangered species, essential fish habitat, 

or historic and archaeological resources, respectively. This appendix contains consultation 

documentation.

The Prairie Island Indian Community (PIIC) submitted a petition to intervene on August 18, 

2008. Any correspondence related to this petition and not specifically to the PINGP 1 and 2

license renewal application review are not listed in the following table or included in this 

appendix. The documents related to this petition that have been submitted to a hearing file, 

which can be found in ADAMS under the adjudicatory process for Prairie Island Nuclear 

Generating Plant, Docket Nos. 050-282 and 050-306.

Table D-1. Consultation Correspondences. This is a list of the consultation 

documents sent between the NRC and other agencies we are required to 

consult with based on NEPA requirements.

Author Recipient Date of Letter

Prairie Island Indian 

Community (Tribal Council)

U.S. Nuclear Regulatory 

Commission (L. Reyes)

January 29, 2008

U.S. Nuclear Regulatory 

Commission (J. Dyer)

Prairie Island Indian Community 

(R. Johnson)

February 23, 2008

U.S. Nuclear Regulatory 

Commission (P.T. Kuo)

Prairie Island Indian Community 

(Tribal Council)

March 21, 2008

Prairie Island Indian 

Community (R. Johnson)

U.S. Nuclear Regulatory 

Commission (S. Lee)

April 14, 2008

Prairie Island Indian 

Community (Tribal Council)

Bureau of Indian Affairs (T. 

Verdin)

May 1, 2008

U.S. Nuclear Regulatory 

Commission (J. Dyer) 

Prairie Island Indian Community 

(R. Johnson)

May 2, 2008

Prairie Island Indian 

Community (H. Westra)

U.S. Nuclear Regulatory 

Commission (N. Le)

May 15, 2008

U.S. Nuclear Regulatory 

Commission (E. Leeds)

Prairie Island Indian Community 

(R. Johnson)

June 14, 2008

U.S. Nuclear Regulatory 

Commission (Staff)

Prairie Island Indian Community 

(Tribal Council)

June 14, 2008

Prairie Island Indian 

Community (P. Mahowald)

U.S. Nuclear Regulatory 

Commission (R. Plasse)

June 17, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Advisory Council on Historic 

Preservation (D. Kilma)

July 10, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Prairie Island Indian Community 

(P. Mahowald)

July 21, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Bureau of Indian Affairs

(T. Verdin)

July 22, 2008
Appendix D

D-2

Author Recipient Date of Letter

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Prairie Island Indian Community 

(H. Westra)

July 22, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Minnesota Department of Natural 

Resources (L. Joyal)

July 22, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

U.S. Fish and Wildlife Service

(T. Sullins)

July 22, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Wisconsin Department of Natural 

Resources (E. Rusch)

July 22, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

State Historic Preservation Office 

(D. Gimmestad)

July 22, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Prairie Island Indian Community 

(R. Johnson) (a)

July 24, 2008

U.S. Fish and Wildlife Service 

(T. Sullins)

U.S. Nuclear Regulatory 

Commission (R. Franovich)

August 13, 2008

Bureau of Indian Affairs

(T. Verdin)

U.S. Nuclear Regulatory 

Commission (R. Franovich)

August 18, 2008

Minnesota Department of 

Natural Resources (H. Cyr)

U.S. Nuclear Regulatory 

Commission (R. Franovich)

August 26, 2008

Wisconsin Department of 

Natural Resources (T. Lovejoy)

U.S. Nuclear Regulatory 

Commission (N. Goodman)

September 8, 2008

U.S. Nuclear Regulatory 

Commission (R. Franovich)

Bureau of Indian Affairs (K. 

Bearquiver)

October 23, 2008

U.S Nuclear Regulatory 

Commission

U.S. Fish and Wildlife Service September 2009

(a)Similar letters went to twenty eight other Native American Tribes listed in Section 1.8.

D.1. Consultation Correspondence

The following pages contain copies of the letters listed in Table D-1. Figures contained in the 

July, 21, 2008, letter (D-26 and D-27) were included with all letters following this date sent by 

the NRC.
Appendix D

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Appendix D

D-70

Biological Assessment

Prairie Island Nuclear Generating Plant, Units 1 and 2

License Renewal

October 2009

Docket Nos. 50-282 and 50-2306

U.S. Nuclear Regulatory Commission

Rockville, Maryland
Appendix D

D-71

Biological Assessment of the Potential Effects on Federally Listed 

Endangered or Threatened Species from the Proposed License Renewal for 

Prairie Island Nuclear Generating Plant, Units 1 and 2

1.0 Introduction and Purpose

The U.S. Nuclear Regulatory Commission (NRC) prepared this biological assessment to 

support the supplemental environmental impact statement (SEIS) for the renewal of the 

operating licenses for Prairie Island Nuclear Generating Plant Units 1 and 2 (PINGP 1 and 2), 

located on the west bank of the Mississippi River in Goodhue County, Minnesota. The current 

40-year licenses for PINGP 1 and 2 expire on August 9, 2013 (DPR-42) and October 29, 2014 

(DPR-60), respectively. The proposed license renewal for which this biological assessment has 

been prepared would extend the operating licenses to 2033 and 2034.

The NRC is required to prepare the SEIS as part of its review of a license renewal application.

The SEIS supplements NUREG-1437, Volumes 1 and 2, “Generic Environmental Impact 

Statement for License Renewal of Nuclear Plants (GEIS),” (NRC 1996, 1999) for the license 

renewal of commercial nuclear power plants. The SEIS covers specific issues, such as the 

potential impact on endangered and threatened species, that are of concern at PINGP 1 and 2 

and that NRC could not address on a generic basis in the GEIS.

Pursuant to Section 7 of the Endangered Species Act of 1973 (ESA), as amended, the NRC 

staff requested, in a letter dated July 22, 2008 (NRC 2008b), that the U.S. Fish and Wildlife 

Service (FWS) provide information on Federally listed endangered or threatened species, as 

well as on proposed or candidate species, and on any designated critical habitats that may 

occur in the vicinity of PINGP 1 and 2. In its response, dated August 13, 2008 (FWS 2008b), the 

FWS indicated that the Higgins eye pearlymussel (Lampsilis higginsii) is present in Upper 

Mississippi River within the vicinity of PINGP 1 and 2, though no designated critical habitat is 

present for the species in Goodhue County. Currently, no Federally listed threatened or 

endangered terrestrial species are known to occur on the PINGP 1 and 2 site or within the inscope transmission line right-of-ways.

Under ESA Section 7, the NRC is responsible for providing information on the potential impact 

that the continued operation of PINGP 1 and 2 could have on the Federally listed species, the 

Higgins eye pearlymussel. The potential affect of relicensing PINGP 1 and 2 on Higgins eye 

pearlymussels occurs through the extending for an additional 20 years the operation of the 

cooling water system, which can affect the mussels and the species on which they depend 

through entrainment, impingement, and changes to the thermal environment. Additional 

information can be found in Chapters 2 and 4 of the SEIS.

2.0 Proposed Action

Northern State Power Co. (NSP) submitted an application for license renewal of PINGP 1 and 2, 

for which the existing licenses expire in 2013 and 2014, respectively. The Federal action is 

NRC’s decision to renew or not renew the licenses for an additional 20 years beyond the 

original 40-year term of operation. Nuclear power plant owners or operators may need to 

undertake or, for economic or safety reasons, may choose to perform refurbishment activities in 

anticipation of license renewal or during the license renewal term. NSP plans to replace two 

steam generators at PINGP Unit 2 to support the extended life of PINGP 1 and 2 through the 

period of extended operation. NSP replaced the steam generators on Unit 1 in 2004, and plans 

to replace the steam generators on Unit 2 in 2013. In Chapter 3 of the SEIS, NRC analyzed 

steam generator replacement as a refurbishment activity as part of license renewal.
Appendix D

D-72

3.0 Site Description

PINGP 1 and 2 are located on Prairie Island on the Mississippi River (Figures 2-1 and 2-22

Prairie Island itself is low-lying and located in a 1- to 3 mi- (1.6- to 4.8 km)-wide section of the 

Mississippi River Valley, with the majority of the island being less than 25 feet (ft; 7.6 meters 

[m]) above the river surface. On either side of the valley are 360-ft (110-m) high bluffs 

composed of Paleozoic limestones and sandstones (Cowdery 1999). Prairie Island is located 

between the Mississippi River and the Vermillion River, with the confluence of the two rivers at 

the downstream end of the island (EPA 2006). About 1.5 mi (2.4 km) downstream from the 

island is Lock and Dam Number 3, which controls the water level and flow of this stretch of the 

Mississippi (USGS 2006). 

).

The Mississippi is the longest river in North America and spans 2302 miles (mi; 3705 kilometers 

[km]) from its source at Lake Itasca in Minnesota to the Gulf of Mexico, where it empties. The 

river drains approximately 189,000 mi2 and 31 different states. The Mississippi can be divided 

into six sub-basins (EPA 2006), and the PINGP 1 and 2 site is located in the Upper Mississippi 

Sub-basin. The Upper Mississippi Sub-basin encompasses over 20,000 mi2 and has 12 major 

tributaries, the most notable being the Missouri River, the Illinois River, the Wisconsin River, 

and the Iowa River (MPCA 2008). 

Prairie Island itself is located on Sturgeon Lake (Figure 2), an area of the Mississippi created by 

the rise in water elevation by Lock and Dam Number 3 and the subsequent flooding of sections 

of the floodplain. The PINGP 1 and 2 cooling system withdraws from and discharges to the main 

stem of the Mississippi River 13 river miles below the confluence of the St. Croix River and 4 

river miles north of where the Vermillion River joins the Mississippi (AEC 1973). Lock and Dam 

3, about 1.5 mi (2.4 km) downstream and Lock and Dam 2, upstream, bound the area of the 

river adjacent to PINGP 1 and 2 known as Pool 3. The two dams lie about 18 river miles (29 

river kilometers) apart (NMC 2008). Immediately northeast of the plant is Sturgeon Lake, a side 

slough or impoundment that would be considered a marsh if it were not associated with the 

main stem of the river (AEC 1973). The Vermillion River borders the southwest portion of the 

site.

 2 Figures 2-1 and 2-2 are taken from Chapter 2 of the draft SEIS for PINGP 1 and 2.
Appendix D

D-73
Appendix D

D-74
Appendix D

D-75

3.1. Cooling and Auxiliary Water Systems

The Mississippi River is the source for cooling water for the main condenser at PINGP 1 and 2.

Cooling river water can be circulated through the station in one of three modes of operation: 

open cycle (once-through cooling, with no cooling towers in operation), helper cycle (oncethrough cooling, with mechanical draft cooling towers in operation), and closed cycle (using 

cooling towers to recirculate up to 95 percent of the cooling water). The mode of operation is 

selected by NSP to limit the heat discharged to the river to ensure compliance with the thermal 

limits of the NPDES permit No. MD0004006 (MPCA 2006; NMC 2008).

The components of the current cooling water system are the eight intake bays, the Intake 

Screenhouse, trash racks, traveling screens, high/low pressure wash systems, fish return 

system, bypass gates, intake canal, Plant Screenhouse, circulating water pumps, condensers, 

discharge basin, mechanical draft cooling towers, discharge canal, and distribution basin. (NMC 

2008)

The Final Environmental Statement (FES) for Operation of PINGP 1 and 2 (AEC 1973) 

describes the original cooling water system. Water was withdrawn from the Mississippi River 

into the 750-ft (230-m)-long intake canal, and into what is now called the Plant Screenhouse.

Inside the screenhouse, the water passed through trash racks and coarse-mesh traveling 

screens to remove fish and debris before supplying the condensers. The plant could operate in 

each of the three modes described above, and so the heated effluent from the plant was either 

pumped to the cooling towers or released to the river, via an 800-ft (240-m)-long canal. In the 

early 1980s, the State of Minnesota directed PINGP 1 and 2 to modify the cooling system to 

reduce impacts to aquatic communities by installing the Intake Screenhouse, equipped with 

trash racks, coarse- and fine-mesh traveling screens, variable pressure wash systems, and a 

fish return system, described below (Stone and Webster 1983).

With the current cooling water system in place, water flows from the river, under a skimmer wall, 

and into the eight intake bay openings, each 18.5 by 11.2 ft (5.6 by 3.4 m), of the Intake 

Screenhouse. The intake bays each have a trash rack, a traveling screen, and high/low 

pressure wash systems, and a fish return system. After passing through the Intake 

Screenhouse, water flows down the intake canal to the Plant Screenhouse, where four 147,000-

gallon-per-minute (gpm; 9.3-cubic meters per second [m3

/s]) circulating water pumps supply 

water to the condensers for a total flow for both units of approximately 588,000 gpm (37.1 m3

/s). 

(NMC 2008)

After leaving the condensers, the cooling water then enters the discharge basin, and from there 

the final path of the cooling water is determined by the operating mode of the plant. In open 

cycle, the cooling water flows from discharge basin, through the distribution basin, into the 

discharge canal, ultimately returning to the Mississippi River. In helper and closed cycles, the 

water is pumped from discharge basin to the cooling towers, and from there returns to the intake 

canal for recirculation (closed cycle) or flows through the distribution basin, into the discharge 

canal, and out to the Mississippi River (helper cycle). A small amount of warm water from the 

discharge canal is pumped to the intake structure to prevent ice formation on trash racks, 

traveling screens, and bypass gates. (NMC 2008)

Intake Screenhouse and Fish Return 

Within the Intake Screenhouse are the trash racks and traveling screens. The trash rack in each 

bay is made of 3/8-inch (in.) by 3-in. (0.95-centimeter [cm] by 7.6-cm) steel bars, mounted on an 

incline 1.5 in. (3.8 cm) apart; a trash rake clears accumulated debris (NMC 2008; Stone and 
Appendix D

D-76

Webster 1983). After passing through the trash rack, the water flows through the traveling 

screens. 

The NPDES permit No. MD0004006, issued June 30, 2006, by the Minnesota Pollution Control 

Agency (MPCA), dictates that from September 1 through March 31, PINGP 1 and 2 may 

operate with up to 3/8-in. (0.95-cm) mesh traveling screens, and that from April 1 through 

August 31, the traveling screens must be 0.5 millimeters (mm; 0.02 in.) fine mesh screens 

(MPCA 2006). Before the cooling water system was modified in 1983, the approach velocity to 

the existing traveling screens was 1.3 feet per second (fps; 0.40 meters per second [m/s]) at 

normal water levels and 1.4 fps (0.43 m/s) at low water levels. The design criteria for the 

average face velocity through the gross area of the screen material for the fine mesh screens 

should not exceed 0.5 fps (0.15 m/s) at low water level and a discharge rate of 800 cubic feet 

per second (cfs; 22.6 m3

/s). Flow measurements taken in 1983 and 1984 were less than 0.66 

fps (0.2 m/s), and most were below 0.33 fps (0.1 m/s). Intake velocities were again studied in 

2003 during coarse mesh screen operation. The authors of the study concluded that the actual 

intake velocities were not outside those design requirements. (Xcel Energy Environmental 

Services 2006)

To remove larvae and fish from the upward travel side of the screen, a low pressure spray is 

used at 10 pounds per square inch (psi; 0.7 kilograms per square centimeter [kg/cm2

]) from the 

inside for the fine mesh screen (larval screenwash), and at 20 psi (1.4 kg/cm2

) from the outside 

when the coarse mesh screen is in use (fish screenwash) (Stone and Webster 1983; NMC 

2008). On the downward travel side of the screen, a high pressure spray from the inside is used 

to remove debris from the screens, at 50 psi (3.5 kg/cm2

) for the fine mesh screen and 100 psi 

(7 kg/cm2

) for the coarse mesh screen (NMC 2008). The fine mesh screens rotate continuously 

between 3 and 20 feet per minute (fpm; 1 and 6 meters per minute [m/min]), based on the 

amount of debris collected; the coarse mesh screens rotate at the same range of speeds when 

the screen differential is higher than 4 in. (10 cm) or if the screens have not rotated for 8 hours 

(Xcel Energy Environmental Services 2006; NMC 2008).

Fish are washed off the upward travel side of the screens into a trough and debris is washed 

from the downward travel side into a separate trough. The troughs combine into a common 

trough and are transported back to the river via a 2200-ft-(670-m)-long, buried pipe, which 

discharges into the river 1500 ft (460 m) south of the Intake Screenhouse, below mean water 

elevation, and at a depth below any ice cover. Fish and debris travel through the pipe at 

velocities between 3 to 5 ft/s (1 to 1.5 m/s), but may speed up in sections of the pipe. (Stone 

and Webster 1983; Xcel Energy Environmental Services 2006; NMC 2008)

If the screens are clogged, the head differential across the traveling screens or across the 

intake screenhouse can become too high and trigger the opening of bypass gates to allow water 

to circumvent the intake screenhouse. The plant screenhouse (part of the original cooling 

system) is still equipped with 3/8-in. screens that remove debris before the water enters the 

condensers, and the intake screens are cleared to minimize the time the bypass gates are 

open. (Stone and Webster 1983)

Discharge and Cooling Tower System 

The discharge basin receives all of the cooling water from the condensers. The path that the 

water takes next is dependent on the operating mode of the cooling system. During open cycle, 

the water flows through the distribution basin, into the discharge canal, and out to the 

Mississippi River. During closed and helper cycles, the water is pumped to the cooling towers.

The cooled water (blowdown) from the cooling towers then moves via the cooling tower return 

canal to the distribution basin. In closed cycle, the distribution basin returns the water to the 
Appendix D

D-77

intake canal to recycle through the condensers. In helper cycle, the distribution basin routes the 

water to the discharge canal and into the river. (NMC 2008)

Water enters the discharge canal through four 10- by 11-ft (3- by 3.4-m) openings to four sluice 

gates operated by motors. The sluice gates lead to four pipes, which vary in diameter [5, 6, 7, 

and 8 ft (1.5, 1.8, 2.1, and 2.4 m)] and are used in different combinations to achieve the desired 

discharge rate. If only the smallest pipe is in use, the discharge rate is 150 cfs (4 m3

/s). If all four 

pipes are used (all sluice gates are open), the maximum discharge rate is 1390 cfs (39 m3

/s), 

and the velocity of the discharging water is 10.17 ft/s (3.1 m/s). (Stone and Webster 1983)

The mechanical draft cooling tower system includes four cooling towers, fans, water distribution 

headers, and basins. Each tower, made up of a bank of 12 sections cells, includes a cooling 

tower pump, which pumps water from the discharge basin through distribution pipes to the top 

of the cooling tower. Spray nozzles disperse the water, which drops through a maze of “fill” to 

the basin at the base of the cooling towers. Fans draw air up through the streams of water, 

evaporating water and allowing the heat to disperse out the top of the cooling towers into the 

atmosphere. The water in the cooling tower basin flows through the cooling tower return canal 

to the distribution basin, where it can either be routed back through the facility’s condensers by 

way of the intake canal (closed cycle) or sent to the discharge canal to return to the Mississippi 

River (helper cycle). The cooling towers can be used for the total circulating water flow of 

588,000 gpm (37.1 m3

/s) and can remove up to 96 percent of the waste heat created by the 

facility. (NMC 2008)

Requirements Under NPDES Permit 

In accordance with the Federal Water Pollution Control Act (or the Clean Water Act [CWA]), 

PINGP 1 and 2 effluent discharges are regulated by the NPDES and State Disposal System 

Permit No. MN0004006 issued and enforced by the MPCA. Section 402 of the CWA states that 

“NPDES prohibits [discharges] of pollutants from any point source into the nation’s waters 

except as allowed under an NPDES permit.” The purpose of this permit is to regulate 

wastewater discharge to preserve the water quality of the surrounding water bodies. As of the 

most recent permit issued, there have been no notices of violation for the PINGP 1 and 2 site. 

Information in this section was obtained from the most recent PINGP 1 and 2 NPDES permit, a 

copy of which is included in the applicant’s license renewal environmental report. The most 

recent renewal of this permit occurred in June 2006 and expires August 2010. 

In order to minimize the impacts from the PINGP 1 and 2 cooling system on entrainment and 

impingement of fish and shellfish, the NPDES permit dictates the screen size the plant must use 

during the spring and summer. Additionally, the NPDES permit imposes limits on the discharge 

of cooling water from April to June, in order to minimize the impacts of entrainment and 

impingement of fish and shellfish. This indirectly restricts the withdrawal rates, as the discharge 

rate approximates the withdrawal rate. 

To minimize the impacts of the heated discharge from the PINGP 1 and 2 cooling system, the 

NPDES permit specifies the times and trigger points when the plant must switch the operating

mode of the cooling system. The permit defines the fall trigger point as when the daily average 

upstream ambient river temperature falls below 43 degrees Fahrenheit (°F; 6 degrees Celsius

[°C]) for five consecutive days. (MPCA 2006)

The only surface discharge aside from the discharge canal outfall (SD 001) that discharges 

directly to the Mississippi is SD 012. SD 012 discharges the plant intake screen backwash as 

well as the fish return system of any impinged fish, aquatic organisms, or debris directly to the 

river. 
Appendix D

D-78

The cooling water discharge restrictions are as follows. From April 15 to April 30 discharge is 

restricted to 194 million gallons per day (mgd; 7.34 x 105 cubic meters per day [m3

/day]) if the 

flow of the Mississippi River is at or above 15,000 cfs (424.8 m3

/s). If the river flow is below this 

level, discharge is limited to 97 mgd (3.67 x 105 m3

/day). From May 1 to May 31 discharge is 

restricted to 194 mgd (7.34 x 105 m3

/day), from June 1 to June 15 it raises to 259 mgd (9.80 x 

105 m3

/day), and from June 16 to 30 is raises again to 517.5 mgd (1.96 x 106 m3/day). Outfall 

SD 001 is permitted to exceed these discharge limitations only in the event that it is necessary 

in order to prevent condenser inlet temperatures from exceeding 85 °F (29 °C). 

Thermal limitations require temperature monitoring at five different locations: the discharge 

canal outfall (SD 001), the plant intake (SW 002), a specified point in the main river channel 

(SW 003), a specified point in Sturgeon Lake (SW 004), and a point directly downstream of Lock 

and Dam No. 3 (SW 001) which is to be monitored using three different temperature probes. 

The permit states that the daily average temperature should under no circumstances exceed 86 

°F (30 °C) and that the temperature of the receiving water should not raise over 5 °F (2.8 °C) 

above the ambient water temperature. The permit specifies that if the ambient water 

temperature reaches 78 °F (26 °C) for two consecutive days, all cooling towers should operate 

to their maximum extent.

4.0 Assessment of Listed Species and Critical Habitat

Life History of Higgins Eye Pearlymussel

The Higgins eye pearlymussel was Federally listed as an endangered species on June 14, 1976 

(41 FR 24064). Although the historical range is not completely known, the Higgins eye was 

never abundant. The current distribution, which includes the Upper Mississippi River above 

Lock and Dam 19 and the St. Croix, Wisconsin, and Rock Rivers, is about half the historical 

range (FWS 2000a). Although FWS (2004a) lists no critical habitat for the species, it has 

designated 10 Essential Habitat Areas for the Higgins eye: Six in the Mississippi River, 3 in the 

St. Croix River, and 1 in the Wisconsin River. The closest Essential Habitat Area to PINGP 1 

and 2 is in the St. Croix River, just upstream of the junction with the Mississippi River, near 

Prescott, Wisconsin (FWS 2004a). FWS (2008a) added four new Essential Habitat Areas far 

downriver in Pools 9, 11, 15, and 16 for a total of 14.

Higgins eye pearlymussels are typically found in large, stable, species-diverse mussel beds in 

medium to large rivers with firm substrate ranging from sand to boulders (FWS 2000a; 2004a).

Water current velocities typical of Higgins eye habitat range from 0.5 to 1.5 fps (1.5 to 4.5 cm/s), 

and depths range from 3.3 to 19.7 ft (1-6 m) (FWS 2000a). To reproduce, males release sperm 

into the water column. As females siphon water for food, they also take in the sperm to fertilize 

eggs in gill sacs (marsupia), where the fertilized eggs mature into glochidia (a larval stage). The 

ribbon-like mantle edge near the posterior of the female acts as a lure to attract fish; when the 

fish attack the mantle, glochidia are released into the water and attach to the gills of the host 

fish. If the glochidia successfully attach to fish gills, they can mature into juvenile mussels 

(typically 3 weeks), excyst from the gills, settle to suitable substrate, and mature into adults.

Some studies suggest glochidia remain in the marsupia through winter and are released in 

spring or summer. (FWS 2000a; FWS 2004a)

Fish known to be suitable hosts for the glochidia of the Higgins eye pearlymussel include 

freshwater drum (Aplodinotus grunniens), largemouth bass (Micropterus salmoides), 

smallmouth bass (M. dolomieu), yellow perch (Perca falvescens), sauger (Stizostedion 

canadense), and walleye (S. vitreum vitreum); marginal fish hosts include northern pike (Esox 

lucius), bluegill (Lepomis macrochirus), and green sunfish (L. cyanellus) (FWS 2004a).
Appendix D

D-79

Status of Higgins Eye Pearlymussel in the Vicinity of PINGP 1 and 2

Currently, the major threat to the Higgins eye pearlymussel, like most other native mussels in 

the Upper Mississippi River, is the invasion of zebra mussels (Dreissena polymorpha), which 

compete for food and space, and even colonize on native mussels. The subfamily Lampsilinae 

to which the Higgins eye belongs is among the most sensitive groups of mussels to zebra 

mussel invasion (FWS 2000a). Researchers have not developed effective and practical 

measures to control zebra mussel populations without harming native aquatic organisms 

(WDNR 2004).

Other threats to the survival of native mussel species, including Higgins eye pearlymussel, 

include dredging, the disposal of dredged material, channelization, and commercial navigation.

The creation of the lock and dam system in the Upper Mississippi River caused pools to replace 

once-flowing water, and the movement of fish species that serve as hosts to native mussel 

species and participate in their distribution are now restricted. Damming the upper Mississippi 

may have favored Higgins eye populations in some pools, because low velocity waters provide 

favorable habitat for the species. Yet some observations indicate that populations of Higgins 

eye in some pools have decreased, possibly due to conditions such as increased 

sedimentation. The net effect of damming the Mississippi River on Higgins eye populations 

therefore remains uncertain. Few documented reports of the commercial harvest of Higgins eye 

exist. (FWS 2000a)

In 1993, the USACE began a consultation with the FWS under Section 7 of the ESA for the 

operation and maintenance of the 9-foot Navigation Project on the Upper Mississippi River. The 

Higgins eye pearlymussel was included in this consultation. As a result, FWS (2000a) issued a 

biological opinion with a jeopardy determination for the Higgins eye. FWS provided reasonable 

and prudent alternatives to allow for the project while offsetting adverse impacts to the species 

involved, including the alternative that USACE develop a Higgins’ eye pearlymussel relocation 

action plan and conduct a study to control the spread of zebra mussels.

The USACE (2002), in cooperation with the Mussel Coordination Team, an interagency team of 

biologists, issued an environmental assessment for a relocation plan of the Higgins eye, with a 

proposal to establish five new populations of the Higgins eye by moving adults from zebra 

mussel-infested areas into sections of the river that had no or low levels of zebra mussels, as 

well as raising juvenile mussels at hatcheries and stocking areas of the river (USACE 2002).

State and Federal agencies, including the FWS, determined that an area within Pool 3, 0.5 mi 

(0.8 km) upstream of the PINGP 1 and 2 intake structure, was a suitable habitat for a relocation 

project for subadult Higgins eye. In 2002, USACE, in cooperation with the Mussel Coordination 

Team, prepared an environmental assessment for the relocation plan for the Higgins eye, in 

which they report “good recovery of mussels” following the relocation of 100 adult Higgins eye

by the Minnesota Department of Natural Resources (MNDNR), the Wisconsin Department of 

Natural Resources (WDNR), and the FWS (USACE 2002). The environmental assessment also 

identified the location as a good relocation site based on the 2000 Minnesota 305(b) water 

quality status report, which listed Pool 3 as providing “full support” for aquatic life (USACE 

2002). Over 4000 sub-adults have been relocated to the Sturgeon Lake section of Pool 3, as of 

the 2005 Status Report (Mussel Coordination Team 2005). The Mussel Coordination Team 

(2005) reported “good recovery” for Pool 3 subadults after conducting monitoring in 2003.

Effects of PINGP 1 and 2 on Higgins Eye Pearlymussel

The cooling water intake structure of a power plant can pose a threat to fish and shellfish, and 

mussels have the potential to be impinged on screens or entrained by the cooling system. The 

life cycle of the Higgins eye pearly mussel renders it unlikely that individuals of this species 

would be at risk of impingement or entrainment. Gravid females carry fertilized eggs until they 
Appendix D

D-80

mature into glochidia. The female uses a lure to attract host fish and releases the glochidia into 

the water column, where they can attach to the gills of the fish; if they fail to attach to the host, 

glochidia are unlikely to attach later and mature into juveniles. Glochidia that successfully attach 

to fish gills mature into juveniles, drop from the gills to the river bottom, and settle on the river 

bottom. Juveniles that settle on suitable substrate mature into adults. Because juveniles and 

adults do not live in the water column, their likelihood of entrainment is very low.

The one period of the life cycle during which the Higgins eye could be at risk from the cooling 

system of a power plant is when the glochidium is attached to the fish host. If the host fish is 

impinged and killed on the screens of the cooling system, the glochidium would be unlikely to be 

able to mature into a juvenile; if it had already matured into a juvenile and dropped off the fish 

while the fish was impinged, it would be swept into the cooling system and entrained. FWS 

(2004) reported that suitable fish hosts for the glochidia of the Higgins eye pearlymussel include 

freshwater drum (Aplodinotus grunniens), largemouth bass (Micropterus salmoides), 

smallmouth bass (Micropterus dolomieu), yellow perch (Perca falvescens), sauger (Sander

canadense), and walleye (S. vitreus vitreus); marginal fish hosts include northern pike (Esox 

lucius), bluegill (Lepomis macrochirus), and green sunfish (Lepomis cyanellus). In its 

Impingement Mortality and Entrainment Characterization Plan, Xcel Energy Environmental 

Services (2006) reported impingement or entrainment of these species during various life 

stages.

The biology of some life stages of some of these host species limits their susceptibility to 

impingement and entrainment by PINGP 1 and 2. The centrarchids (largemouth and smallmouth 

bass, bluegill, and green sunfish) build nests where they spawn and the males guard the eggs 

and larvae for weeks to months, depending on the species. The eggs of the centrarcheds and 

percids (yellow perch, sauger, and walleye) are demersal and sticky, and so are not particularly 

vulnerable to entrainment. The larvae of these percids, however, are planktonic, and vulnerable 

to entrainment. Only the freshwater drum has planktonic eggs and larvae, and Xcel Energy 

(2006) reports high numbers of these impinged on the PINGP 1 and 2’s fine-mesh screens. Xcel 

Energy (2006) also reported that immediate impingement survival of prolarvae and postlarve of 

all fish species is low, averaging 7.2 and 5.5 percent, respectively, and but did not measure or 

estimate the more meaningful, longer-term incipient survival, which would be even lower.

Juvenile freshwater drum, sunfish, and percids are impinged, but the average immediate 

survival of all juvenile fish impinged on the fine-mesh screens is relatively high (71.5 percent 

(Xcel Energy 2006), although incipient survival is unknown. The adults of the host fish species 

typically can swim fast enough to have low vulnerability, although Xcel Energy (2006) reports 

impingement of some adult percids and centrarchids on the fine-mesh screens. When taken 

together, these results suggest that populations of fish species that serve as hosts for Higgins 

eye pearlymussel have some limited vulnerability to entrainment and impingement at PINGP 1 

and 2, at least locally, that might result in somewhat reduced population numbers. NRC staff 

finds that any such reductions, if they occur, would not adversely affect Higgins eye 

pearlymussels, however, because no population of the Higgins eye has been reported in the 

vicinity of the plant. 

5.0 Conclusion

In order to assess the potential adverse affects on the Higgins eye pearlymussel, the NRC staff 

considered the life cycle of the Higgins eye, the limited time the mussel spends in the water 

column during which it could be subject to entrainment, and the low probability of the primary 

fish hosts for the species being impinged (and therefore the even lower probability of a fish host 

being impinged while carrying Higgins eye glochidia). In addition, Higgins eye pearlymussels 
Appendix D

D-81

were not found in the area around Lock and Dam 3 in studies conducted in 1986, 1999, 2000, 

and 2003. The NRC staff concludes that renewal of the PINGP 1 and 2 licenses to operate for 

an additional 20 years is not likely to adversely affect Higgins eye pearlymussel.

NRC staff also recognizes that the FWS determined that the area just upstream of the PINGP 1 

and 2 intake structure is a suitable site for the Higgins eye relocation project. If that project is 

successful in establishing a reproducing population of Higgins eye during the renewal term of 

the licenses, impingement and entrainment at PINGP 1 and 2 of suitable fish hosts may 

adversely affect the mussel population. Therefore, NRC may have to re-assess the potential for 

adverse effects at some time in the future. 

6.0 References

AEC (Atomic Energy Commission). 1973. Final Environmental Statement Related to the 

Operation of Prairie Island Nuclear Generating Plant. Washington, D.C. ADAMS No. 

ML081840311.

Cowdery, T.K. 1999. Water Resources of the Prairie Island Indian Reservation, Minnesota, 

1994-1997. Water-Resources Investigation Report 99-4069. U.S. Geological Survey. Available 

URL: http://mn.water.usgs.gov/pubs/99-4069.pdf (accessed October 10, 2008).

EPA (U.S. Environmental Protection Agency). 2006. Mississippi River Basin & Gulf of Mexico 

Hypoxia Upper Mississippi, Background on Upper Mississippi River Basin. Available URL: 

http://www.epa.gov/msbasin/subbasins/upper/index.htm (accessed on October 10, 2008). 

ADAMS No. ML083120233.

FWS (U.S. Fish and Wildlife Service). 2000a. Biological Opinion for the Operation and 

Maintenance of the 9-Food Navigation Channel on the Upper Mississippi River System. U.S. 

Fish and Wildlife Service, Division of Endangered Species, Fort Snelling, Minnesota. Available 

URL: http://www.fws.gov/midwest/endangered/section7/umrbofinal.pdf (accessed September 

25, 2008).

FWS (U.S. Fish and Wildlife Service). 2004a. Higgins Eye Pearlymussel (Lampsilis higginsii) 

Recovery Plan: First Revision. Ft. Snelling, Minnesota. 126 pp. Available URL: 

http://ecos.fws.gov/docs/recovery_plans/2004/040714.pdf (accessed August 27, 2008).

FWS (U.S. Fish and Wildlife Service). 2008a. Higgins eye (Lampsilis higginsii) Essential Habitat 

Areas 2008 Review and Addition of New EHAs. U. S. Fish and Wildlife Service - Twin Cities

Ecological Services Field Office, Bloomington, MN. 9 p. Available URL:

http://www.fws.gov/midwest/Endangered/clams/pdf/hepmEHA.pdf (accessed May 4, 2011).FWS 

(U.S. Fish and Wildlife Service). 2008b. Letter from T. Sullins, U.S. Fish and Wildlife Service, 

Twin Cities Ecological Services Office, to R. Franovich, Branch Chief, Division of License 

Renewal. Subject: Request for List of Federally Protected Species Within the Area Under 

Evaluation for the Prairie Island Nuclear Generating Plant, Units 1 and 2, License Renewal 

Application Review. August 13, 2008. ADAMS No. ML082470303.

MPCA (Minnesota Pollution Control Agency). 2006. National Pollutant Discharge Elimination 

System, Permit MN0004006, Prairie Island Nuclear Generating Plant. June. ADAMS No.

MPCA (Minnesota Pollution Control Agency). 2008. Upper Mississippi River Basin. Available 

URL: http://www.pca.state.mn.us/water/basins/uppermiss/index.html (accessed October 10, 

2008). ADAMS No. ML083380243. 

Mussel Coordination Team. 2005. Status of Implantation of Higgins Eye Pearlymussel 

(Lampsilis higginsii) Reasonable and Prudent Alternatives and Reasonable and Prudent 
Appendix D

D-82

Measures and Winged Mapleleaf (Quadrula fragosa) Reasonable and Prudent Measures.

November 2005. Available URL: 

http://www.fws.gov/Midwest/mussel/documents/status_higgins_eye_winged_mapleleaf_2005.pd

f (accessed December 12, 2008).

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NRC (U.S. Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, Washington, D.C. 

ADAMS Nos. ML040690705 and ML040690738.

NRC (U.S. Nuclear Regulatory Commission). 1999. Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants, Main Report, Section 6.3 – Transportation, Table 9.1, 

Summary of findings on NEPA issues for license renewal of nuclear power plants, Final Report.

NUREG-1437, Volume 1, Addendum 1, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 2008b. Letter from U.S. Nuclear Regulatory 

Commission to T. Sullins, U.S. Fish and Wildlife, Twin Cities Ecological Services Office.

Subject: Request for List of Federally Protected Species Within the Area Under Evaluation for 

the Prairie Island Nuclear Generation Plant, Units 1 and 2, License Renewal Application 

Review. July 22, 2008. Accessible at ML081850485.

Stone and Webster (Stone and Webster Engineering Corp.). 1983. Modify Circulating Water 

Intake and Discharge: System Description and Design Criteria. Prepared for Northern States 

Power Co. Denver. April 1, 1983. ADAMS No. ML0831202223.

USACE (US Army Corps of Engineers). 2002. Final July 2002 Definite Project Report and 

Environmental Assessment for Relocation Plan for the Endangered Higgins’ Eye Pearlymussel 

(Lampsilis higginsii), Upper Mississippi River and Tributaries, Minnesota, Wisconsin, Iowa, and 

Illinois. In cooperation with the Mussel Coordination Team. July. Available URL: 

http://www.fws.gov/Midwest/mussel/documents/ dpr_relocation_plan_final_july_2002.pdf 

(accessed August 27, 2008).

USGS (U.S. Geological Survey). 2006. Water Resources Data, Minnesota, Water Year 2005:

Water Data Report MN-05-051. April 5, 2006. ADAMS No. ML028806950

WDNR (Wisconsin Department of Natural Resources). 2004. Zebra Mussels (Dreissena 

polymorpha). Available URL: http://dnr.wi.gov/invasives/fact/ zebra.htm (accessed September 

11, 2008). ADAMS No. ML083380525.

Xcel Energy Environmental Services. 2006. Xcel Energy Prairie Island Nuclear Generating 

Plant, Impingement Mortality and Entrainment Characterization Study. Submitted in Accordance 

with the NPDES Final Regulations to Establish Requirements for Cooling Water Intake 

Structures at Phase II Existing Facilities, NPDES Permit MN0004006. October 12. ADAMS No. 

ML0831202.

APPENDIX E

CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE


E-1

E. Chronology of Environmental Review Correspondence

This appendix contains a chronological listing of correspondence between the U.S. Nuclear 

Regulatory Commission (NRC) and external parties as part of its environmental review for 

Prairie Island Nuclear Generating Plant, Units 1 and 2. All documents, with the exception of 

those containing proprietary information are available electronically from the NRC’s Public 

Electronic Reading Room found on the Internet at the following Web address: 

http://www.nrc.gov/reading-rm.html. From this site, the public can gain access to the NRC’s 

Agencywide Document Access and Management System (ADAMS), which provides text and 

image files of NRC’s public documents in ADAMS. The ADAMS accession number for each 

document is included below.

E.1 Environmental Review Correspondence

January 29, 2008 Letter from the Prairie Island Indian Community, regarding 

potential application to renew the license for the Prairie Island 

Nuclear Generating Plant, Units 1 and 2 (ADAMS Accession 

No. ML080390402).

February 23, 2008 Letter to Ronald Johnson, Prairie Island Indian Community, 

regarding anticipated license renewal review for Prairie Island 

Nuclear Generating Plant, Units 1 and 2 (ADAMS Accession 

No. ML080460246).

March 21, 2008 Letter to Ronald Johnson, Prairie Island Indian Community, 

regarding request for cooperating agency status for the Prairie 

Island Nuclear Generating Plant, Units 1 and 2, license renewal 

environmental review (ADAMS Accession No. ML080710522).

April 11, 2008 Letter from NMC forwarding the application for renewal of 

operating license for Prairie Island Nuclear Generating Plant, 

Units 1 and 2, requesting an extension of operating license for 

an additional 20 years (ADAMS Accession No. ML081130666).

April 14, 2008 Letter from the Prairie Island Indian Community, “Re: Request 

for Cooperating Agency Status” (ADAMS Accession No. 

ML081080036).

April 28, 2008 Letter to NMC, “Receipt and Availability of the License Renewal 

Application for the Prairie Island Nuclear Generating Plant, 

Units 1 and 2” (ADAMS Accession No. ML081050091).

May 1, 2008 Letter from the Prairie Island Indian Community to Terry Virden, 

Bureau of Indian Affairs, regarding Prairie Island Nuclear 

Generating Plant, Units 1 and 2, license renewal review 

(ADAMS Accession No. ML0814006650).

May 2, 2008 Letter to Ronald Johnson, Prairie Island Indian Community, 

regarding request to participate as a cooperating agency 

(ADAMS Accession No. ML081200867).
Appendix E

E-2

May 6, 2008 Federal Register notice, “Nuclear Management Company, LLC; 

Notice of Receipt and Availability of Application for Renewal of 

Prairie Island Nuclear Generating Plant, Units 1 and 2, Facility 

Operating License Nos. DPR-42 and DPR-60 for an Additional 

20-Year Period” (73 FR 25034).

May 13, 2008 NRC press release announcing the availability of the license 

renewal application for Prairie Island Nuclear Generating Plant, 

Units 1 and 2, for public inspection (ADAMS Accession No. 

ML081340103).

May 15, 2008 Email from Heather Westra, Prairie Island Indian Community, 

transmitting the markup of the draft Memorandum of 

Understanding (ADAMS Accession Nos. ML081630551 and 

ML081630555).

May 19, 2008 Letter to NMC forwarding the correction to notice of receipt and 

availability of the license renewal application for the Prairie 

Island Nuclear Generating Plant, Units 1 and 2” (ADAMS 

Accession No. ML081330711).

June 10, 2008 Letter to NMC, “Determination of Acceptability and Sufficiency 

for Docketing, Proposed Review Schedule, and Opportunity for 

a Hearing Regarding the Application from Nuclear 

Management Company, LLC, for Renewal of the Operating 

Licenses for the Prairie Island Nuclear Generating Plant, Units 

1 and 2” (ADAMS Accession No. ML081370273).

June 14, 2008 Letter to Ronald Johnson, Prairie Island Indian Community, 

transmitting the Memorandum of Understanding between the 

U.S. Nuclear Regulatory Commission and the Prairie Island 

Indian Community as a Cooperating Agency for the Prairie 

Island Nuclear Generating Plant, Units 1 and 2, license renewal 

environmental review (ADAMS Accession No. ML081610245).

June 14, 2008 Memorandum of Understanding between the U.S. Nuclear 

Regulatory Commission and the Prairie Island Indian 

Community as a Cooperating Agency (ADAMS Accession No. 

ML081610273).

June 17, 2008 Federal Register notice, “Nuclear Management Company, LLC, 

Prairie Island Nuclear Generating Plant, Units 1 and 2, Notice 

of Acceptance for Docketing of the Application and Notice of 

Opportunity for Hearing Regarding Renewal of Facility 

Operating License Nos. DPR-42 and DPR-60 for and Additional 

20-Year Period” (73 FR 34355).

June 17, 2008 Letter from Philip R. Mahowald, Prairie Island Indian 

Community, transmitting the fully executed Memorandum of 

Understanding between the U.S. Nuclear Regulatory 

Commission and the Prairie Island Indian Community as a 

Cooperating Agency (ADAMS Accession No. ML081710160).

June 26, 2008 Letter to NMC, “Notice of Intent to Prepare and Environmental 

Impact Statement and Conduct Scoping Process for License 
Appendix E

E-3

Renewal for the Prairie Island Nuclear Generating Plant, Units 

1 and 2” (ADAMS Accession No. ML081620382).

June 26, 2008 NRC press release, “NRC and Prairie Island Indian Community 

Sign First-of-a-Kind Memorandum of Understanding” (ADAMS 

Accession No. ML081780445).

July 10, 2008 Letter to Don L. Klima, Advisory Council on Historic 

Preservation, inviting participation in scoping process related to 

NRC’s environmental review of the license renewal application 

for Prairie Island Nuclear Generating Plant, Units 1 and 2 

(ADAMS Accession No. ML081850189).

July 15, 2008 Letter to NMC, “Notice of Intent to Prepare and Environmental 

Impact Statement and Conduct Scoping Process for License 

Renewal for the Prairie Island Nuclear Generating Plant, Units 

1 and 2” (ADAMS Accession No. ML081970679).

July 17, 2008 Memorandum to Rani Franovich, NRC, “Forthcoming Meeting 

to Discuss the License Renewal and Environmental Scoping 

Process for the Prairie Island Nuclear Generating Station, Units 

1 and 2, License Renewal Application” (ADAMS Accession No. 

ML081910743).

July 21, 2008 Letter to Philip R. Mahowald, Prairie Island Indian Community, 

“Request for Scoping Comments Concerning the Prairie Island 

Nuclear Generating Plant, Units 1 and 2, License Renewal 

Application Review” (ADAMS Accession No. ML081850414).

July 22, 2008 Federal Register notice, “Nuclear Management Company, LLC, 

Prairie Island Nuclear Generating Plant, Units 1 and 2, Notice 

of Intent to Prepare an Environmental Impact Statement and 

Conduct Scoping Process” (73 FR 42628).

July 22, 2008 Letter to Terrance Virden, U.S. Bureau of Indian Affairs, inviting 

participation in scoping process related to NRC’s environmental 

review of the license renewal application for Prairie Island 

Nuclear Generating Plant, Units 1 and 2 (ADAMS Accession 

No. ML081930470).

July 22, 2008 Letter to Heather Westra, Prairie Island Indian Community, 

inviting participation in scoping process related to NRC’s 

environmental review of the license renewal application for 

Prairie Island Nuclear Generating Plant, Units 1 and 2 (ADAMS 

Accession No. ML081850178).

July 22, 2008 Letter to Lisa A. Joyal, Minnesota Department of Natural 

Resources, “Request for List of State-Protected Species and 

Important Habitats Within the Area Under Evaluation for the 

Prairie Island Nuclear Generating Plant, Units 1 and 2, License 

Renewal Application Review” (ADAMS Accession No. 

ML081890395).

July 22, 2008 Letter to NMC, “Revision of Schedule for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 and 2, License 

Renewal Application” (ADAMS Accession No. ML081980353).
Appendix E

E-4

July 22, 2008 Letter to Tony Sullins, U.S. Fish and Wildlife Service, “Request 

for List of Federally Protected Species Within the Area Under 

Evaluation for the Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Review Application” (ADAMS 

Accession No. ML081850485).

July 22, 2008 Letter to Emily Rusch, Wisconsin Department of Natural 

Resources, “Request for List of State-Protected Species Within 

the Area Under Evaluation for the Prairie Island Nuclear 

Generating Plant, Units 1 and 2, License Renewal Application 

Review” (ADAMS Accession No. ML081930340).

July 22, 2008 Letter to Dennis A. Gimmestad, State Historic Preservation 

Officer, Minnesota Historical Society, inviting participation in 

scoping process related to NRC’s environmental review of the 

license renewal application for Prairie Island Nuclear 

Generating Plant, Units 1 and 2 (ADAMS Accession No. 

ML081840682).

July 24, 2008 Letter to Ronald Johnson, Prairie Island Indian Community,(a) 

inviting participation in scoping process related to NRC’s

environmental review of the license renewal application for 

Prairie Island Nuclear Generating Plant, Units 1 and 2 (ADAMS 

Accession No. ML082070095).

July 25, 2008 NRC press release, “NRC Seeks Public Input on Environmental 

Impact Statement for Prairie Island License Renewal Review” 

(ADAMS Accession No. ML082070110).

July 30, 2008 Letter to NMC, “Environmental Site Audit Regarding Prairie 

Island Nuclear Generating Plant, Units 1 and 2, License 

Renewal Application” (ADAMS Accession No. ML082040527).

July 30, 2008 Summary of telephone conference call held on July 2, 2008, 

between the NRC and the Prairie Island Indian Community, 

concerning the license renewal of Prairie Island Nuclear 

Generating Plant, Units 1 and 2 (ADAMS Accession No. 

ML082050652).

August 13, 2008 Letter from Tony Sullins, U.S. Fish and Wildlife Service, 

regarding request for list of Federally protected species within 

the area under evaluation for the Prairie Island Nuclear 

Generating Plant, Units 1 and 2, license renewal application 

review (ADAMS Accession No. ML082470303).

August 18, 2008 Letter from Kevin Bearquiver, U.S. Bureau of Indian Affairs, 

regarding invitation to participate in scoping process related to 

NRC’s environmental review of the license renewal application 

for Prairie Island Nuclear Generating Plant, Units 1 and 2 

(ADAMS Accession No. ML081470304).

August 26, 2008 Letter from Heidi Cyr, Minnesota Department of Natural 

Resources, “Re: Request for Natural Heritage Information in 

the Vicinity of the Prairie Island Nuclear Generating Plant” 

(ADAMS Accession Nos. ML083290584 and ML083290592).
Appendix E

E-5

September 8, 2008 Letter from Tom Lovejoy, Wisconsin Department of Natural 

Resources, “Prairie Island Nuclear Generating Plant License 

Renewal – EIS Scoping Issues” (ADAMS Accession No. 

ML083080277).

September 8, 2008 Letter from Xcel Energy transmitting “Prairie Island Nuclear 

Generating Plant License Renewal Environmental Report 

Additional Information: Documents Requested During NRC 

Environmental Review” (ADAMS Accession No. 

ML083120219).

September 26, 2008 Letter from Xcel Energy, “Submittal of Documents for Public 

Disclosure as Requested During NRC License Renewal 

Environmental Audit” (ADAMS Accession No. ML083120218).

September 29, 2008 Letter from Xcel Energy, “Submittal of Archaeological 

Documents Requested During NRC License Renewal 

Environmental Audit” (ADAMS Accession No. ML082880304).

October 23, 2008 Letter to Kevin Bearquiver, U.S. Bureau of Indian Affairs, 

“Response to Letter from K. Bearquiver Regarding Prairie 

Island Nuclear Generating Plant, Units 1 and 2, License 

Renewal Application Review” (ADAMS Accession No. 

ML082820382).

October 23, 2008 Letter to NMC, “Request for Additional Information for the 

Review of the Prairie Island Nuclear Generating Plant, Units 1 

and 2, License Renewal Application (ADAMS Accession No. 

ML0829505510).

October 23, 2008 Attachment to letter to NMC, “Request for Additional 

Information for the Review of the Prairie Island Nuclear 

Generating Plant, Units 1 and 2, License Renewal Application” 

(ADAMS Accession No. ML082950604).

(a)Similar letters went to twenty eight other Native American Tribes listed in Section 1.8.

APPENDIX F

U.S NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

SEVERE ACCIDENT MITIGATION ALTERNATIVES (SAMAS) FOR

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2, IN 

SUPPORT OF LICENSE RENEWAL APPLICATION REVIEW
F-2
F-1

F. U.S Nuclear Regulatory Commission Staff Evaluation of Severe 

Accident Mitigation Alternatives (SAMAs) for Prairie Island Nuclear 

Generating Plant, Units 1 and 2, in Support of License Renewal 

Application Review

F.1. Introduction

Northern States Power Company (NSP) submitted an assessment of severe accident mitigation 

alternatives (SAMAs) for Prairie Island Nuclear Generating Plant, Units 1 and 2, (PINGP 1 and 

2) as part of the Environmental Report (ER) (NMC 2008). This assessment was based on the 

most recent PINGP 1 and 2 Probabilistic Risk Assessment (PRA) available at that time, a plantspecific offsite consequence analysis performed using the MELCOR Accident Consequence 

Code System 2 (MACCS2) computer code, and insights from the PINGP 1 and 2 Individual 

Plant Examination (IPE) (NSP 1994) and Individual Plant Examination of External Events 

(IPEEE) (NSP 1998). In identifying and evaluating potential SAMAs, NSP considered SAMAs 

that addressed the major contributors to core damage frequency (CDF) and large early release 

frequency (LERF) at PINGP 1 and 2, as well as SAMA candidates for other operating plants that 

have submitted license renewal applications. NSP identified 25 potential SAMA candidates for 

each unit. This list was reduced to nine unique SAMA candidates for each unit by eliminating 

SAMAs that: are not applicable at PINGP 1 and 2 because of design differences, have already 

been implemented, have no significant benefit or have benefits which have been achieved by 

other means, or require extensive changes that would involve implementation costs known to 

exceed any possible benefit. NSP assessed the costs and benefits associated with each of the 

potential SAMAs and concluded that several of these would be potentially cost-beneficial.

Based on a review of the SAMA assessment, the U.S. Nuclear Regulatory Commission (NRC) 

issued requests for additional information (RAI) to NSP by letters dated October 23, 2008 (NRC 

2008a) and December 24, 2008 (NRC 2008b). Key questions concerned: unit-to-unit differences 

and their treatment in the PRA model, PRA peer review and quality controls, treatment of 

reactor coolant pump (RCP) seal LOCA and induced steam generator tube rupture (SGTR) 

events in the PRA, justification for the multiplier used for external events, the identification and 

screening of internal flood related enhancements, and further information on several specific 

candidate SAMAs and potential lower-cost alternatives. NSP submitted additional information by 

letters dated November 21, 2008 (NSP 2008), and January 23, 2009 (NSP 2009a). In the 

responses, NSP provided: descriptions of unit-to-unit differences and how they were reflected in 

the PRA, further information regarding the PRA peer review and self-assessments, additional 

analyses of the impact of alternative RCP seal LOCA model and induced SGTR model 

assumptions on SAMA results, additional information regarding external event SAMAs and 

justification for the treatment of external events, additional information regarding internal flood 

related enhancements and their screening, and additional information regarding several specific 

SAMAs. NSP’s responses addressed the NRC staff’s concerns and resulted in the identification 

of several additional potentially cost-beneficial SAMAs.

An assessment of SAMAs for PINGP 1 and 2 is presented below.

F.2. Estimate of Risk for PINGP 1 and 2

NSP’s estimates of offsite risk at PINGP 1 and 2 are summarized in Section F.2.1. The 

summary is followed by the NRC staff’s review of NSP’s risk estimates in Section F.2.2.
Appendix F

F-2

F.2.1. NSP’s Risk Estimates

Two distinct analyses are combined to form the basis for the risk estimates used in the SAMA 

analysis: (1) the PINGP 1 and 2 Level 1 and Level 2 PRA model, which is an updated version of 

the IPE (NSP 1994), and (2) a supplemental analysis of offsite consequences and economic 

impacts (essentially a Level 3 PRA model) developed specifically for the SAMA analysis. The 

SAMA analysis is based on the most recent PINGP 1 and 2 Level 1 and Level 2 PRA model 

available at the time of the ER, referred to as the Rev. 2.2 (SAMA) model. The scope of the 

PINGP 1 and 2 PRA does not include external events.

The baseline CDF for the purpose of the SAMA evaluation is approximately 9.79 × 10-6 per year 

for Unit 1 and 1.21 × 10-5 per year for Unit 2. The CDF is based on the risk assessment for 

internally initiated events including internal flooding. NSP did not include the contribution from 

external events within the PINGP 1 and 2 risk estimates; however, it did account for the 

potential risk reduction benefits associated with external events by doubling the estimated 

benefits for internal events. This is discussed further in Sections F.2.2 and F.6.2.

The breakdown of CDF by initiating event is provided in Table F-1. As shown in this table, 

events initiated by small LOCA, loss of cooling water and loss of offsite power are the dominant 

contributors to internal event CDF for each unit. Although not separately reported, station 

blackout sequences contribute about 9 percent and 8 percent for Unit 1 and 2, respectively, of 

the total internal events CDF, while anticipated transient without scram (ATWS) sequences 

contribute about 2 percent and 1 percent for Unit 1 and 2, respectively (NSP 2008). The 

differences in the CDF contributions result largely from several differences between the two 

PINGP 1 and 2 units. Section F.2.2 discusses these differences in greater detail.

Table F-1. PINGP Core Damage Frequency

Unit 1 Unit 2

Initiating Event CDF 

(per year)

% 

Contribution 

to CDF

CDF 

(per year)

%

Contribution 

to CDF

Small LOCA 4.8 x 10-6 49 5.4 x 10-6 45

Loss of Cooling Water 1.8 x 10-6 18 1.8 x 10-6 15

Loss of Offsite Power 1.0 x 10-6 11 1.2 x 10-6 10

Loss of Main Feedwater 3.9 x 10-7 4 4.1 x 10-7 3

Medium LOCA 3.4 x 10-7 3 5.4 x 10-7 4

Loss of Component Cooling 

Water 

2.9 x 10-7 3 2.9 x 10-7 2

Large LOCA 2.8 x 10-7 3 3.1 x 10-7 3

Internal Flooding 2.4 x 10-7 2 2.4 x 10-7 2

Normal Transient 2.4 x 10-7 2 2.8 x 10-7 2

Steam Generator Tube Rupture 

(STGR)

1.9 x 10-7 2 1.1 x 10-6 9

Loss of Train A DC 3.8 x 10-8 <1 4.0 x 10-7 3

Other 2.1 x 10-7 2 1.7 x 10-7 1

Total CDF (internal events) 9.79 x 10-6 100 1.21 x 10-5 100
Appendix F

F-3

The current PINGP 1 and 2 Level 2 PRA model is based on the IPE models with updates to 

reflect changes to the plant and modeling techniques, including the steam generator 

replacement for Unit 1. The Level 1 core damage sequences are assigned to core damage bins 

(plant damage states) that provide the interface between the Level 1 and Level 2 analyses. The 

Level 2 models use containment event trees (CETs) with functional nodes representing both 

systemic and phenomenological events. CET nodes are evaluated using supporting fault trees 

and event trees.

The result of the Level 2 PRA is a set of 18 release categories with their respective frequency 

and release characteristics. The frequency of each release category was obtained by summing 

the frequency of the CET endstates assigned to each release category. Source terms were 

developed for each of the release categories using the results of Modular Accident Analysis 

Program (MAAP) 3.0B computer code calculations. The 18 release categories were collapsed 

into 10 bounding release categories used for the SAMA analysis. The release categories and 

their release characteristics are presented in Tables F.3-5 and F.3-6 of the ER.

The offsite consequences and economic impact analyses use the MACCS2 code to determine 

the offsite risk impacts on the surrounding environment and public. Input for these analyses 

includes plant-specific and site-specific values for core radionuclide inventory, source term and 

release characteristics, site meteorological data, projected population distribution (within an 80-

km [50-mi] radius) for the year 2034, emergency response evacuation modeling, and economic 

data. The magnitude of the onsite impacts (in terms of cleanup and decontamination costs and 

occupational dose) is based on information provided in NUREG/BR-0184 (NRC 1997a).

NSP estimated the dose to the population within 50 mi of the PINGP 1 and 2 site to be 

approximately 2.94 person-rem per year for Unit 1 and 8.37 person-rem per year for Unit 2. The 

breakdown of the total population dose by containment release mode is summarized in Table F2. This table reflects minor corrections to several entries provided by NSP in response to an RAI 

(NSP 2008). Releases due to steam generator tube rupture (SGTR) events, interfacing system 

loss-of-coolant accidents (ISLOCAs), and late containment failures dominate the population 

dose risk at PINGP 1 and 2.

Table F-2. Breakdown of Population Dose by Containment Release Mode

Containment Release 

Modes

Unit 1 Unit 2

Population Dose

(person-rem(a)

per year)

Percent 

Contribution

Population Dose

(person-rem(a)

per year)

Percent 

Contribution

Intact 

Containment

Normal 

Leakage

0.01 0.4 0.01 0.2

Early 

Containment 

Failure

Over-pressure 

Failure

0.12 4.1 0.14 1.7

Isolation 

Failure

<0.01 0.1 <0.01 <0.1

Late 

Containment 

Failure

Basemat 

Failure

0.63 21.4 0.76 9.0

Over-pressure 

Failure

0.12 4.1 0.12 1.4

Containment 

Bypass

SGTR 1.32 44.9 6.66 79.0

ISLOCA 0.74 25.0 0.74 8.7

Total 2.94 100 8.43 100
Appendix F

F-4

F.2.2. NRC Staff’s Review of NSP’s Risk Estimates

NSP’s determination of offsite risk at PINGP 1 and 2 is based on the following three major 

elements of analysis:

• the Level 1 and 2 risk models that form the basis for the 1994 IPE 

submittal (NSP 1994) and the external events analyses of the 1998 IPEEE submittal 

(NSP 1998),

• the major modifications to the IPE model that have been incorporated into 

the PINGP 1 and 2 PRA, and

• the MACCS2 analyses performed to translate fission product source 

terms and release frequencies from the Level 2 PRA model into offsite consequence 

measures.

Each of these analyses was reviewed to determine the acceptability of NSP’s risk estimates for 

the SAMA analysis, as summarized below.

The NRC staff’s review of the PINGP 1 and 2 IPE is described in an NRC report dated May 16, 

1997 (NRC 1997b). On the basis of a review of the IPE submittal, the staff concluded that the 

IPE submittal met the intent of Generic Letter (GL) 88-20; that is, the IPE was of adequate 

quality to be used to look for design or operational vulnerabilities. Although no vulnerabilities 

were identified in the IPE, several plant improvements were identified. These improvements 

have either been implemented at the site or addressed by a SAMA in the current evaluation.

These improvements are discussed in Section F.3.2. 

There have been over five revisions to the Level 1 model since the 1994 IPE submittal. A 

comparison of the internal events CDF between the IPE and the Rev. 2.2 (SAMA) PRA model 

indicates a decrease of approximately 80 percent for both units (from 5.0 × 10-5 per year to 

9.79 × 10-6 per year for Unit 1). A comparison of the contributors to the total CDF indicates that 

the frequency of each major contributor (e.g., LOCAs, loss of offsite power (LOOP), internal 

flooding) has decreased by factors of 2 to 10 since the IPE. A description of those changes that 

resulted in the greatest impact on the internal events CDF is provided in Section F.2.1 of the ER 

(NMC 2008) and in response to an RAI (NSP 2008a), and is summarized in Table F-3.

Table F-3. PINGP 1 and 2 PRA Historical Summary

PRA Version Summary of Changes from Prior Model Unit 1 CDF 

(per year)

Unit 2 CDF 

(per year)

1994 (Rev. 0) • IPE submittal 5.0 x 10-5 NA

Rev. 1.0 • 1996 Update

• Added selected balance-of-plant systems

• Updated the plant safeguards electrical 

systems

• Updated component failure and 

unavailability data for six key systems

• Reanalyzed LOCA frequencies

2.4 x 10-5 NA

Rev. 1.1 • 1999 Update

• Changed PRA quantification to a single 

top fault tree approach

2.4 x 10-5 NA
Appendix F

F-5

PRA Version Summary of Changes from Prior Model Unit 1 CDF 

(per year)

Unit 2 CDF 

(per year)

Rev. 1.2 • 2001 Update

• Resolved selected Westinghouse Owners 

Group PRA Certification Team Review 

comments

• Updated component failure rates

2.2 x 10-5 NA

Rev. 2.0 • 2002 Update

• Developed a Unit 2 PRA model from 

Unit 1

• Removed boric acid storage tank input to 

the safety injection pumps suction logic

• Enhanced existing quantification 

methodology

• Modified charging pump system fault tree 

logic to include an operator action to 

restart the pumps after a LOOP event

• Modified RHR to include the same 

common cause failure event in the 

injection, recirculation and shutdown 

cooling modes

• Added operator action to prevent load 

sequencer failure

• Updated logic modeling for the 

supply/exhaust fans

2.2 x 10-5 2.5 x 10-5

Rev. 2.1 • 2005 Update

• Updated LOOP initiating frequency

• Updated various system fault trees

• Upgraded the human reliability analysis 

(HRA)

• Corrected the process used to model preinitiator latent errors

• Added modeling of 120 V AC panel faults

• Updated failure and common cause data 

for EDG and AFW systems

• Updated internal flooding analysis

1.5 x 10-5 1.6 x 10-5

Rev. 2.2 • 2006 Update

• Closed all remaining Level B WOG Peer 

Certification Review findings

• Updated initiating event frequency to 

reflect the installation of new steam 

generators (for Unit 1 only)

9.8 x 10-6 1.1 x 10-5
Appendix F

F-6

PRA Version Summary of Changes from Prior Model Unit 1 CDF 

(per year)

Unit 2 CDF 

(per year)

Rev. 2.2 

(SAMA)

• 2006 Update

• Corrected Units 1 and 2 Level 1 core 

damage sequence success logic for the 

small LOCA event

9.8 x 10-6 1.2 x 10-5

The IPE CDF value for PINGP 1 and 2 was the lowest CDF value reported in the IPE for 

Westinghouse two-loop plants. Figure 11.6 of NUREG-1560 shows that the IPE-based total 

internal events CDF for Westinghouse two-loop plants ranges from 5 × 10-5 to 1.2 × 10-4 per 

reactor-year (NRC 1997c). It is recognized that other plants have updated the values for CDF 

subsequent to the IPE submittals because of modeling and hardware changes. The internal 

events CDF based on the latest PRA (9.79 × 10-6 per year and 1.21 × 10-5 per year for Units 1 

and 2, respectively) remains lower than the latest CDF values reported in the license renewal 

applications for other two-loop Westinghouse plants, which are in the range of 3 × 10-5 to 

4 × 10-5 per year. The NRC staff concludes that although lower than for the other two-loop 

plants, the current internal events CDF results for PINGP 1 and 2 are still reasonably consistent 

with that for plants of similar vintage and characteristics.

The ER identifies several design differences between Unit 1 and Unit 2. The NRC staff 

requested additional information on how the differences between the units impacted core 

damage frequency and release frequencies. In its response, NSP identified the following unit 

differences and their estimated impacts (NSP 2008):

• As the result of a motor-driven Auxiliary Feedwater (MDAFW) pump control 

power asymmetry, the Loss of Train A DC initiating event contributes more 

significantly to the Unit 2 CDF (4.0 x 10-7 per year) than it does to the Unit 1 

CDF (3.8 x 10-8 per year) because the loss of this bus results in the loss of 

main feedwater and the loss of breaker control power for the Unit 2 MDAFW 

pump. The Unit 1 pump is not impacted. The control power asymmetry also 

contributes to a higher potential for induced SGTR on Unit 2 due to the 

inability of one AFW pump to automatically start on loss of Train A DC power 

increasing the potential for the event to degrade into a core damage event at

high pressure due to loss of heat sink.

• The Unit 1 emergency diesel generators (EDGs) are the original EDGs that 

provided backup power to both units, while the Unit 2 EDGs were added in 

response to the Station Blackout (SBO) Rule and differ in manufacturer, 

design, capacity, and in the external systems required to support their 

operation. Due to the independent design of the EDGs between units 

combined with the ability to cross-tie the 4kV buses across units, the 

contribution to the CDF from a loss of all AC power is less than 10 percent for 

both units.

• A Unit 1 steam generator replacement project was completed in 2004, while 

the replacement of the Unit 2 steam generators has not yet been completed.

Therefore, there is a lower potential for an SGTR-initiated core damage event 

at Unit 1. The licensee notes that the Level 2 PRA analysis does not credit a 

possibly lower potential for pressure- and temperature-induced SGTR events 

on Unit 1. 
Appendix F

F-7

The NRC staff considered the peer review performed for the PINGP 1 and 2 PRA, and the 

potential impact of the review findings on the SAMA evaluation. In the ER (NMC 2008) and in 

response to NRC staff RAIs (NSP 2008 and 2009), NSP described the peer review by the 

(former) Westinghouse Owners Group (WOG) of the 1994 PRA model (i.e., the IPE) conducted 

in September 2000. NSP states that the WOG review concluded that the PINGP 1 and 2 PRA 

can be effectively used to support applications involving relative risk significance. NSP further 

states that all Level A (important and necessary to address before the next regular PRA update) 

and Level B (important and necessary to address, but disposition may be deferred until the next 

PRA update) facts and observations (F&Os) from the peer review have been resolved.

In response to an RAI (NSP 2008), NSP noted that one of the F&Os involved the PRA 

maintenance and update process, and had been subsequently resolved. In a follow-up 

response (NSP 2009a), NSP described two procedures that were developed to address this 

F&O. One procedure addresses the maintenance and update process to ensure that the PRA 

represents the as-built, as-operated plant such that it is sufficient to support applications for 

which the PRA is being used. The other provides instructions on how to structure the 

quantification of the PRA model following a periodic or maintenance update of the PRA model, 

and prescribes reviews that should be performed (e.g., of cutsets, recovery actions, mutually 

exclusive events, circular logic, asymmetries, initiating event distributions, and important 

operator actions). NSP states that the PRA model quantification procedure/guideline was 

created to meet the model quantification element in the ASME PRA standard.

In addition to the WOG Peer Certification review, NSP stated that the PINGP 1 and 2 PRA 

model has been reviewed three times as part of the self-assessment process (NSP 2009a). 

These three reviews were: (1) the PRA Program Snapshot Evaluation, in April 2007, that 

benchmarked the PINGP 1 and 2 PRA against Regulatory Guide 1.200, Revision 1, “An 

Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for 

Risk-Informed Activities,” (2) the PRA Program Focused Self-Assessment, in May 2004, that 

assessed the PRA Program against the NMC Fleet PRA Standard and industry best practices, 

and (3) the Nuclear Oversight Observation Report, in June 2003, that reviewed the PINGP 1 

and 2 PRA Risk Assessment Program against NUMARC 93-01, “Industry Guideline for 

Monitoring the Effectiveness of Maintenance Activities at Nuclear Power Plants.”

The NRC staff noted that the PINGP 1 and 2 PRA uses a Westinghouse reactor coolant pump 

seal loss-of-coolant accident (LOCA) model that pre-dates the WOG 2000 model approved by 

the NRC in 2003 for plants using high-temperature O-rings. In addition, the WOG Peer Review, 

discussed above, occurred prior to the approval of the WOG 2000 model, and as such would 

not have identified the use of an older model as an issue. In response to an RAI (NSP 2009a), 

NSP stated that all four of the Prairie Island’s installed RCPs have been updated with high 

temperature O-rings, that high temperature O-rings and hard seal parts manufactured by Areva 

have been evaluated and accepted as interchangeable with the same parts manufactured by 

Westinghouse, and that Westinghouse and Areva O-rings and hard seal parts are installed in 

various combinations in all four RCPs. NSP states that although the Areva O-rings have been 

qualified for the same high temperature service as the Westinghouse O-rings, there may be a 

difference in the beyond design basis failure pressure characteristics. As this difference has not 

been resolved, NSP performed a sensitivity analysis using the Rhodes model (as presented in 

WCAP-16141) with a bounding 480-gpm per pump leakage rate. In conjunction with this 

sensitivity analysis, NSP integrated the impact of migrating from MAAP 3.0B (on which the 

current model is based) to MAAP 4.0.6. NSP stated that this change was made because MAAP 

3.0B is known to be significantly conservative with respect to the timing of core uncovery and 

core damage following initiation of RCP seal LOCA events. The results of this sensitivity 

analysis showed an estimated 22 percent (1.9 × 10-7 per year) increase in CDF for SBO events.
Appendix F

F-8

However, NSP argued that when sufficient plant-specific MAAP analysis case runs are available 

to allow modeling of the lower leakage rates specified in the Rhodes model, it is anticipated that 

the contribution to overall CDF will actually be lower than currently calculated. In consideration 

of the above factors, the NRC staff concludes that NSP’s use of its current RCP model is 

reasonable for the purposes of the SAMA evaluation.

In response to an NRC inquiry into the bases for not implementing two IPE-identified internal 

flooding enhancements, NSP identified a potential model limitation associated with the use of 

deterministic arguments to address an estimate of the probabilistic pipe break frequency 

associated with a Cooling Water System flood in the Auxiliary Feedwater Pump/Instrument Air 

Compressor Room. In response to this issue, NSP has entered into their Corrective Action 

Program the re-evaluation of selected flooding enhancements to be performed after the PRA 

limitation has been corrected (NSP 2009b). This issue is fully discussed in Section F.3.2. As 

NSP’s actions directly address the identified model limitation by including the previously 

screened improvements in their Corrective Action Program for future evaluation, the NRC staff 

finds that NSP actions adequately address the impact of this model limitation on the SAMA 

evaluation.

Given that the PINGP 1 and 2 Level 1 internal events PRA model has been both peer reviewed 

and subjected to an extensive self-assessment process and the review findings have been 

resolved or judged to have no adverse impact on the SAMA evaluation, and that NSP has 

satisfactorily addressed NRC staff questions regarding the PRA, the NRC staff concludes that 

the Level 1 PRA model is of sufficient quality to support the SAMA evaluation.

As indicated above, the current PINGP 1 and 2 PRA models do not include external events. In 

the absence of such an analysis, NSP used the PINGP 1 and 2 IPEEE in conjunction with minor 

adjustments in fire and seismic scenarios to identify the highest risk accident sequences and the 

potential means of reducing the risk posed by those sequences, as discussed below.

The PINGP 1 and 2 IPEEE was submitted in December 1996, in response to Supplement 4 of 

GL 88-20 (NSP 1996). NSP did not identify any vulnerabilities to severe accident risk in regard 

to the external events related to seismic, fire, or other external events. This submittal included a 

seismic margins analysis, a fire-induced vulnerability evaluation, and a screening analysis for 

other external events. In a letter dated February 8, 2001, the NRC staff concluded that the 

submittal met the intent of Supplement 4 to GL 88-20, and that the licensee’s IPEEE process is 

capable of identifying the most likely severe accidents and severe accident vulnerabilities (NRC 

2001b).

The PINGP 1 and 2 IPEEE details how NSP had originally planned to respond to GL 88-20, 

Supplement 4, by performing a seismic PRA for Prairie Island, but changed the approach of 

completing the seismic IPEEE from a seismic PRA to a Seismic Margins Assessment (SMA).

This change was based on information incorporated in Supplement 5 of GL 88-20, regarding 

large reductions in the seismic hazard estimates for sites in the eastern United States. The 

seismic margin assessment follows the NRC guidance (NRC 1991) and Electric Power 

Research Institute (EPRI) guidance (EPRI 1991) and was completed in conjunction with the 

Seismic Qualification User Group (SQUG) program (SQUG 1992). This method is qualitative 

and does not provide the means to determine the numerical estimates of the CDF from seismic 

initiators. The conclusions of the PINGP 1 and 2 IPEEE seismic margin analysis found that all 

components included in the SAMA have high confidence low probability of failure (HCLPFs) 

greater than or equal to 0.3 g with the exception of the component cooling water heat 

exchangers. As the component cooling water heat exchangers have HCLPFs of 0.28g, the 

PINGP 1 and 2 IPEEE states that they are considered to be adequate. The IPEEE findings also 

included one recommendation to restrain or remove wall hung ladders and scaffolding located 
Appendix F

F-9

near safety related equipment and 22 outliers designated for resolution under the A-46 program 

where each outlier represents one or more like components (NSP 1996, NSP 2000 and NRC 

2001a). All A-46 outliers were either resolved or scheduled for resolution by the May 1999 Unit 

1 outage (NRC 1998b).

In response to a NRC staff request for information regarding the seismic contribution to risk, 

NSP stated that a bounding estimate of seismic risk was developed in support of another NRC 

submittal using a methodology known as the “Simplified Hybrid Method” (Kennedy 1999). Using 

this method NSP provided a seismic core damage frequency estimate of 7.8 x 10-6 per year 

(NSP 2008). An independent estimate of 2.5 x 10-6 per year was developed by NRC staff based 

on the simplified seismic methodology and 2008 updated U. S. Geological Survey (USGS) 

seismic hazard information (USGS 2008), which confirms the bounding nature of NSP’s 

estimate.

The PINGP 1 and 2 IPEEE fire analysis employed a combination of classical PRA techniques 

with EPRI’s Fire Induced Vulnerability Evaluation (FIVE) methodology. The FIVE methodology 

was used to establish fire boundaries and to evaluate the probability and the timing of damage 

to components located in a compartment involved in a fire. Each fire area that remained after an 

initial qualitative screening was evaluated for fire detection and suppression, and fire growth and 

propagation. Fire scenarios that were found to have the potential to spread beyond the initiating 

compartment were examined and addressed. All remaining fire areas were assessed using a 

bounding estimate (“all-engulfing fire”) against a screening criterion of 1 x 10-6 per year. The 

remaining fire areas were subjected to a more detailed fire analysis. The CDF for each of these 

areas was obtained by accounting for the frequency of a fire in a given fire area, conditional 

core damage probability associated with that fire scenario in the fire area including, and where 

appropriate, the impact of fire suppression. The potential impact on containment performance 

and isolation was evaluated following the core damage evaluation. The total fire CDF from the 

IPEEE was estimated to be less than 5 × 10-5 per year (NSP 1998). The dominant fire scenarios 

and their contributions to the fire CDF are listed in Table F-4.

Table F-4. Significant Fire Areas for PINGP 1 and 2

Fire Area Description CDF (per year)

FA 13 Control Room 3.22 x 10-5

FA 32 Train “B” Hot Shutdown Panel and Air Compressor/AFW 

Room

8.23 x 10-6

FA 80 480V Safeguards Switchgear Room-Bus 111 2.24 x 10-6

FA 20 4160V Safeguards Switchgear Room-Bus 16 1.74 x 10-6

FA 59 Aux Building Mezzanine 1.45 x 10-6

FA 73 Aux Building Ground Floor 1.28 x 10-6

FA 18 Relay & Cable Spreading Room 1.08 x 10-6

FA 69 Turbine Building Ground and Mezzanine Floor 1.08 x 10-6
Appendix F

F-10

The NRC staff notes that the fire results are based on the Unit 1 fire analysis. An evaluation of 

the applicability of the Unit 1 results to Unit 2 is included in the PINGP IPEEE (NSP 1998). This 

evaluation notes that there are potentially significant asymmetries between the units including:

• The Unit 2 4160 V safeguard bus rooms have been identified in the Appendix 

R Shutdown Analysis as being of concern for loss of offsite power to Unit 2.

This is not expected for the corresponding Unit 1 rooms.

• The emergency buses (Buses 25 and 26) for Unit 2 are located in fire areas 

that are not separated by Appendix R-credited fire barriers from the diesel 

generators. This separation exists for Unit 1.

• Cooling Water pump power supply asymmetries result in: a greater impact of 

a fire on Pump 121 for Unit 2 than Unit 1, greater electrical separation 

between diesel and motor-driven pumps for Unit 2, and a lesser impact of 

Unit 2 switchgear fires on Pumps 11 and 21.

The IPEEE states that the asymmetries associated with Unit 2’s increased potential for loss of 

offsite power has the impact of raising the Unit 2 fire risk, while the independence of the 

operation of the two diesel cooling water pumps from Unit 2 AC power tends to offset this risk 

increase. Based on this, the NRC staff concludes that the use of the Unit 1 fire risk results to 

support the SAMA analysis for both units is reasonable.

In the ER (NMC 2008), the licensee noted that a number of conservative assumptions were 

used in the fire analysis. Further, in response to staff RAIs, NSP stated that the IPEEE Fire 

analysis was performed in order to meet GL 88-20 requirements (identify vulnerabilities to 

severe accidents initiated by internal fires), that the analysis was not intended to determine the 

internal fires CDF to a high degree of accuracy, and that it is not appropriate to compare a 

conservative CDF estimate for fire hazards to the present-day internal events CDF (NSP 2008).

The conservatisms identified by NSP include:

• All fires were assumed to result in shutdown of both units therefore limiting 

the ability to credit system cross-ties.

• Credit for automatic and manual suppression was limited to cutsets 

representing less than 13 percent of the internal fires CDF.

• No credit was given to the ability of fire brigade to extinguish local fires before 

shutdown of the plant.

• Credit for manual suppression was only applied to the Control Room, Relay 

Room, and certain AFW pump room fires. Credit for automatic fire 

suppression was only applied in the AFW pumps rooms.

• No credit was given to the availability of the RCS pressure operated relief 

valve (PORV) passive air accumulators. Any fire that impacted the instrument 

air system was assumed to result in the loss of the ability to perform RCS 

bleed and feed.

• Detailed fire modeling was not performed in a number of fire areas that did 

not screen out.

In response to a follow-up request to better clarify the identified conservatisms, NSP provided 

additional rationale as to why the fire CDF would be lower. This included quantitative estimates 

of the extent to which the fire results would be reduced through the use of updated fire ignition 

frequencies and conditional core damage probabilities, and additional credit for automatic and 

manual fire suppression. NSP indicated that based on the more recent methodology of 
Appendix F

F-11

NUREG/CR-6850, the fire ignition frequencies for the Control Room and the AFW/Instrument 

Air Compressor Room would be approximately 40 percent lower than calculated in the IPEEE.

They also noted that relative to the Level 1 Revision 1 internal events model used for the fire 

IPEEE analysis, the conditional core damage probability (CCDP) based on the updated internal 

events PRA model (Rev 2.2 SAMA) has been reduced by 46 percent for normal (or general) 

plant transient initiated events (NSP 2008), 32 percent for loss of main and auxiliary feedwater 

initiated events, and 81 percent for loss of offsite power initiated events. With respect to the 

credit for fire suppression, NSP stated that within the control room, manual suppression was 

only credited in fires that were large enough to propagate beyond the boundaries of the initiating 

Control Room panel zone, and that this credit for successful fire suppression was limited to 

cutsets representing less than 13 percent of the internal fires CDF (NSP 2009a). Based on the 

quantitative information provided by NSP, the NRC staff estimates that use of the updated fire 

ignition frequencies and conditional core damage probabilities, and additional credit for fire 

suppression would result in about a factor of 3 reduction in the fire CDF.

The NRC staff finds that NSP provided reasonable justification that that the ignition frequency 

for risk significant fire areas would be less than previously analyzed and that the CCDP for fire 

sequences is also lower. NRC staff also agrees that the assumption that any fire initiated in a 

Control Room panel zone (regardless of intensity, location or other factors) damages all 

equipment within the zone appears conservative for the purposes of the SAMA evaluation and 

that only limited credit was given to fire suppression. The NRC staff concludes that when all the 

qualitative and quantitative factors are taken into consideration, a realistic estimate of the 

PINGP 1 and 2 fire CDF would likely be in the range of 1 x 10-5 per year. 

The IPEEE analysis of other external events (NSP 1998) followed the screening specified in 

Supplement 4 to GL 88-20 (NRC 1991) and did not identify any unduly significant sequences or 

vulnerabilities. The plant design was reviewed to determine if it met 1975 Standard Review Plan 

design criteria for high winds, floods, and other external events. If it met these criteria and a 

walkdown did not identify any unique vulnerabilities, then the CDF from the external hazard was 

considered to be less than 1 × 10-6 per year. If it did not meet the criteria, then additional 

analysis was performed to evaluate the specific concern. Since the plant design for high wind 

effects did not conform fully to the criteria specified in the 1975 SRP, high winds and tornadoes 

could not be screened out. Further analysis summarized in the IPEEE SER (NRC 2001b) 

indicated that the CDF due to high winds and tornadoes is less than 1 × 10-6 per year.

In the ER, NSP estimated that the external events CDF is comparable to the internal events 

CDF. Accordingly, the total CDF from internal and external events would be approximately 2 

times the internal events. In the SAMA analysis, NSP doubled the benefit that was derived from 

the internal events model to account for the combined contribution from internal and external 

events (NMC 2008). In response to an RAI requesting justification for increasing the benefits by 

only a factor of 2, NSP provided additional information regarding the estimated CDF for seismic 

events and the conservatisms in the CDF, as described above. In consideration of this 

additional information, the NRC staff concurs that the external event CDF is comparable to that 

for internal events at PINGP 1 and 2 (based on a seismic CDF of 2.5 × 10-6 per year, a fire CDF 

of 1 × 10-5 per year, and a CDF of 1 × 10-6 per year for other external events), and concludes 

that the licensee’s use of a multiplier of 2 to account for external events is reasonable for the 

purposes of the SAMA evaluation.

The NRC staff reviewed both the general process used by NSP to translate the results of the 

Level 1 PRA into containment releases and the results of the Level 2 analysis, as described in 

the ER and in response to the NRC staff RAIs (NSP 2008 and 2009). The current PINGP 1 and 

2 Level 2 PRA model is based on the IPE models with updates to reflect changes to the plant 

and modeling techniques, including the steam generator replacement for Unit 1. The Level 1 
Appendix F

F-12

core damage sequences are assigned to core damage bins (plant damage states) that provide 

the interface between the Level 1 and Level 2 analyses. The Level 2 models use CETs with 

functional nodes representing both systemic and phenomenological events. CET nodes are 

evaluated using supporting fault trees and event trees. The result of the Level 2 PRA is a set of 

18 release categories with their respective frequency and release characteristics. The frequency 

of each release category was obtained by summing the frequency of the CET endstates 

assigned to each release category. Source terms were developed for each of the release 

categories using the results of MAAP 3.0B computer code calculations. The 18 release 

categories were collapsed into 10 bounding release categories used for the SAMA analysis. The 

release categories and their release characteristics are presented in Tables F.3-5 and F.3-6 of 

the ER.

The NRC staff’s review of the Level 2 IPE for PINGP 1 and 2 concluded that it addressed the 

most important severe accident phenomena normally associated with a large, freestanding steel 

shell containment, and identified no significant problems or errors (NRC1997b). The Level 1 

plus LERF model was included in the PINGP 1 and 2 peer review mentioned previously. NSP 

states that all Level A and B F&Os have been resolved. As noted above, additional reviews 

have been performed since the completion of the WOG peer review. It also should be noted, 

however, that the current Level 1 plus LERF model is a revision to the version that was peer 

reviewed. The changes to the Level 1 plus LERF and the full Level 2 model are described in 

Section F.2.1.3 of the ER and in response to an RAI (NMC 2008, NSP 2008). The PINGP 1 and 

2 Level 2 PRA is based on Revision 2.2 which was developed in 2006, and incorporates several 

changes that were implemented subsequent to the peer review. These changes to the model 

include: the elimination of induced SGTR events in Revision 1 of the Level 2 PRA model, but reintroduction of these events in the Revision 2.2 model update used for the SAMA analysis; 

changes to the human error probability for failure to cool down and depressurize the RCS 

following a SGTR; and the addition of a containment isolation fault tree for each unscreened 

containment penetration to model the failure of containment isolation. 

During the review of the Level 2 analysis, the NRC staff could not determine the modeling 

approach used to assess the likelihood of a thermally-induced SGTR following core damage in 

the current PRA. In response to an RAI, NSP stated that the treatment of induced SGTR events 

follows the guidance of WCAP-16341-P, “Simplified Level 2 Modeling Guidelines.” WCAP16341-P was developed by the WOG with the intent that Level 2 models developed using its 

methodology would meet requirements of the ASME PRA standard (ASME 2002). Additional 

discussion on NSP modeling of induced SGTR is provided in Section F.6.2 including the results 

of a sensitivity analysis in which the conditional probability of an induced SGTR was increased.

Based on the NRC staff’s review of the Level 2 methodology, the fact that the Level 2 model 

was reviewed in more detail as part of the WOG peer review and updated to address peer 

review findings, the staff’s review of the subsequent Level 2 model changes, and NSP’s 

responses to the RAIs, the NRC staff concludes that the PINGP 1 and 2 Level 2 PRA provides 

an acceptable basis for evaluating the benefits associated with various SAMAs.

As indicated in the ER, the reactor core radionuclide inventory used in the consequence 

analysis is based on a plant-specific calculation and corresponds to end-of-cycle values (core 

average exposure of 50,000 MWD/MTU). All releases were modeled as occurring at the top of 

the Containment Building. The thermal content of each of the releases is assumed to be 107

watts based on values provided in Sample Problem A in the MACCS2 user’s manual (NRC 

1998a) and NUREG/CR-4551 (NRC 1990). NSP assessed the impact of alternatively assuming 

either a ground level release or an ambient (non-buoyant) plume. The results of these sensitivity 

cases showed that reducing the release height to ground level results in about a 2 percent 

increase in the 50-mile population dose risk and a 6 percent decrease in offsite economic cost 
Appendix F

F-13

risk, and reducing the thermal plume heat content to ambient conditions results in a negligible 

change in population dose risk and a 6 percent decrease in offsite economic cost risk.

The NRC staff reviewed the process used by NSP to extend the containment performance 

(Level 2) portion of the PRA to an assessment of offsite consequences (essentially a Level 3 

PRA). This included consideration of the source terms used to characterize fission product 

releases for the applicable containment release categories and the major input assumptions 

used in the offsite consequence analyses. The MACCS2 code was utilized to estimate offsite 

consequences. Plant-specific inputs to the code includes the source terms for each release 

category and the reactor core radionuclide inventory (both discussed above), site-specific

meteorological data, projected population distribution within a 50-mi radius for the year 2034, 

emergency evacuation modeling, and economic data. This information is described in Section 

F.3 of the ER (NMC 2008).

NSP used site-specific meteorological data for the 2003 calendar year as input to the MACCS2 

code. The data were collected from the onsite meteorological tower. Data from 2004 and 2005 

were also considered, but the 2003 data were chosen because they were the most complete 

and because results of a MACCS2 sensitivity analyses indicated that the 2003 data produced 

more conservative results than the data sets for the other years. Small data voids (five gaps of 

less than six consecutive hours) were filled using interpolation between data points. Larger data 

voids (three gaps of six or more consecutive hours) were filled using data from the same time of 

day from the day just before or after the missing data. The NRC staff notes that previous SAMA 

analyses results have shown little sensitivity to year-to-year differences in meteorological data 

and concludes that the use of the 2003 meteorological data in the SAMA analysis is reasonable.

The population distribution the licensee used as input to the MACCS2 analysis was estimated 

for the year 2034, based on the U.S. Census Bureau population data for 2000, as provided by 

the SECPOP2000 program (NRC 2003), and the expected annual population growth rate. The 

baseline population was determined for each of sixteen directions and each of ten concentric 

rings (total of 160 sectors) out to a radius of 50 miles (80 km) surrounding the site. U.S Census 

block-group level population data was allocated to each sector based on the area fraction of the 

census block-groups in that sector. The 1990 and 2000 census data from SECPOP2000 were 

used to estimate an annual average population growth rate for each of the 50-mile (80 km) 

radius rings. The annual growth rate estimate for each ring was applied uniformly to all sectors 

in the ring to calculate the year 2034 population distribution. Population sensitivity cases were 

performed in which the baseline 2034 population was increased by 30 percent, and then 

decreased to the year 2000 population data rather than the projected year 2034 population. The 

resulting population dose and offsite economic cost risk increased by approximately 30 percent 

and decreased by approximately 40 percent, respectively. The NRC staff considers the methods 

and assumptions for estimating population reasonable and acceptable for purposes of the 

SAMA evaluation.

The emergency evacuation model was modeled as a single evacuation zone extending out 10 

miles (16 km) from the plant. NSP assumed that 95 percent of the population would evacuate.

This assumption is conservative relative to the NUREG-1150 study (NRC 1990), which 

assumed evacuation of 99.5 percent of the population within the emergency planning zone. The 

evacuees were assumed to begin evacuating 90 minutes after a General Emergency has been 

declared and to evacuate at an average radial speed of 3.35 miles per hour (1.5 meters per 

second). This speed is the time weighted value accounting for season, day of the week, time of 

day, weather conditions, and special events. A sensitivity analysis was performed in which the 

evacuation speed was decreased by a factor of two (to 0.75 meters per second). The result was 

a 2 percent increase in the total population dose. The NRC staff concludes that the evacuation 
Appendix F

F-14

assumptions and analysis are reasonable and acceptable for the purposes of the SAMA 

evaluation.

Much of the site-specific economic data were provided from SECPOP2000 (NRC 2003) by 

specifying the data for each of the counties surrounding the plant to a distance of 50 miles.

SECPOP2000 utilizes economic data from the 1997 Census of Agriculture (USDA 1998) and 

from other 1998 and 1999 data sources. Generic economic data that applies to the region as a 

whole was taken from the MACCS2 sample problem input and revised when better information 

was available. Revised values included daily living expenses for people who have been 

evacuated and relocated, and the value of farm and non-farm wealth. The economic data were 

inflation-adjusted to the year 2006 using the consumer price index. 

NSP addressed the impact on the SAMA analysis of three recently reported problems with 

SECPOP2000. These problems involved: (1) an inconsistency in the format in which several 

economic parameters were output from the SECPOP2000 code and input to the MACCS2 code, 

(2) an error that resulted in use of agricultural/economic data for the wrong counties in the 

SECPOP2000 calculations, and (3) an error that resulted in the economic data for some 

counties being handled incorrectly. NSP states in Section F.3.1 of the ER that all three errors 

have been addressed in the PINGP 1 and 2 analyses provided in the ER via industry-developed 

formatting fixes, and that the MACCS2 outputs used to quantify economic impacts have been 

verified to be correct (NMC 2008).

The NRC staff concludes that the methodology used by NSP to estimate the offsite 

consequences for PINGP 1 and 2 provides an acceptable basis from which to proceed with an 

assessment of risk reduction potential for candidate SAMAs. Accordingly, the NRC staff based 

its assessment of offsite risk on the CDF and offsite doses reported by NSP.

F.3. Potential Plant Improvements

The process for identifying potential plant improvements, an evaluation of that process, and the 

improvements evaluated in detail by NSP are discussed in this section.

F.3.1. Process for Identifying Potential Plant Improvements

NSP's process for identifying potential plant improvements (SAMAs) consisted of the following 

elements:

• Review of the most significant basic events from the Rev. 2.2 (SAMA) version 

of the PINGP 1 and 2 Level 1 and 2 PRA for each unit,

• Review of potential plant improvements identified in the PINGP 1 and 2 IPE 

and IPEEE,

• Review of dominant contributors to seismic and fire events in the current 

external event risk models,

• Review of Phase II SAMAs from license renewal applications for eleven other 

U.S. nuclear sites, and

• Input from PINGP 1 and 2 Group during the PRA update process and the 

development of the SAMA list.

On the basis of this process, an initial set of 25 candidate SAMAs, referred to as Phase I 

SAMAs, was identified for Unit 1 and Unit 2. In Phase I of the evaluation, NSP performed a 
Appendix F

F-15

qualitative screening of the initial list of SAMAs and eliminated SAMAs from further 

consideration using one of the following criteria:

• The SAMA is not applicable at PINGP 1 and 2 because of design differences;

• The SAMA has already been implemented at PINGP 1 and 2;

• The SAMA has no significant benefit in PWRs such as PINGP 1 and 2;

• The SAMA has benefits which have been achieved by other means; and

• The SAMA requires extensive changes that would involve implementation 

costs known to exceed any possible benefit.

Based on this screening, 16 SAMAs were eliminated, leaving nine for further evaluation. The 

remaining SAMAs, referred to as Phase II SAMAs, are listed in Table F.5-3 of the ER (NMC 

2008). In Phase II, a detailed evaluation was performed for each of the nine remaining SAMA 

candidates, as discussed in Sections F.4 and F.6 below. To account for the potential impact of 

external events, the estimated benefits based on internal events were multiplied by a factor of 2, 

as previously discussed.

F.3.2. Review of NSP’s Process

NSP’s efforts to identify potential SAMAs focused primarily on areas associated with internal 

initiating events, but also included explicit consideration of potential SAMAs for seismic, fire, and 

high wind events. The initial list of SAMAs generally addressed the accident sequences 

considered to be important to CDF from functional, initiating event, and risk reduction worth 

(RRW) perspectives at PINGP 1 and 2, and included selected SAMAs from other plants.

NSP provided a tabular listing of the PRA basic events sorted according to their RRW (NMC 

2008). SAMAs impacting these basic events would have the greatest potential for reducing risk.

NSP used a RRW cutoff of 1.02, which corresponds to about a 2 percent change in CDF given 

100-percent reliability of the SAMA. This equates to a benefit of approximately $22,000 for Unit 

1 and $58,000 for Unit 2 (after the benefits have been doubled to account for external events).

NSP also provided and reviewed the LERF-based RRW events down to an RRW of 1.02. NSP 

correlated the top CDF and LERF events with the SAMAs evaluated in Phase I or Phase II and 

showed that, with a few exceptions, all of the significant basic events are addressed by one or 

more SAMAs (NMC 2008). Of the basic events of high risk importance that are not addressed 

by SAMAs, each is closely tied to other basic events that had been addressed by one or more 

SAMAs.

The NRC staff noted that the top two events in the Level 1 importance listing shown in Table 

F.5-1a of the ER, involve failure of operator actions (Operator Fails to Perform RCS Cooldown 

and Depressurization on Small LOCA, and Operator Fails to Initiate High Head Recirculation 

(conditional on failure of the first action)). Improvements for these actions were dismissed by 

NSP due to the large uncertainty regarding the operator failure probability estimates. The NRC 

requested additional clarification on the characteristics of these actions that prevents further 

improvement in operator performance (and lower calculated human error probability values).

NSP stated that both of these operator actions are emergency operating procedure-driven and 

are trained on at least once during a 2-year training cycle (NSP 2008). In a follow-up response, 

NSP included a detailed discussion on the critical role timing plays for these actions showing 

that there is limited time available for recovery and that the second action is questioned on 

failure of the first therefore lowering its success likelihood (NSP 2009a). In consideration of the 

above factors, the NRC staff concludes that improvements in these actions are unlikely for the 

purposes of the SAMA evaluation.
Appendix F

F-16

The NRC staff noted that the description of the screening criteria provided in Section 4.17.1 of 

the ER (and summarized in Section F.3.1 above), is different than that provided in Section F.5.2 

of the ER. In response to an NRC staff request for clarification regarding the actual screening 

criteria used, NSP provided a mapping of the screened candidate SAMAs to the two sets of 

criteria. For most screened SAMAs, the “no significant benefit” criterion of Section 4.17.1 was 

equated to the engineering judgment criterion found in Section F.5.2. Although the approach of 

listing two sets of screening criteria and the inclusion of an “engineering judgment” criterion was 

found to be confusing, the NRC staff did not identify any candidate SAMAs as being 

inappropriately screened.

For a number of the Phase II SAMAs listed in the ER, the information provided did not 

sufficiently describe the proposed modifications or other considerations that might have been 

taken into account in estimating the benefit and implementation cost. Therefore, the NRC staff 

requested and the licensee provided more information on certain proposed modifications listed 

for the Phase II SAMA candidates. The requested information included clarification of the $300K 

implementation cost for SAMA 2 (Install alternate cooling water supply), description of the basis 

for the $2M per unit cost for SAMA 6a (Segregate Auxiliary Building flooding zones), and 

clarification of the $100K life-cycle cost for SAMA 20 (Close low head injection motor operated 

valves (MOVs) to prevent RCS backflow to safety injection system) (NRC 2008a, NSP 2008).

The responses to these requests are discussed in Section F.5.

For several SAMA candidates, the NRC staff questioned if lower cost alternatives could have 

been considered, and identified a number of specific alternatives for further consideration by 

NSP. In response, NSP addressed the lower cost alternatives and gave specific reasons why 

the cost of most of these alternative SAMA candidates would be high enough that the decision 

on final SAMA selection would not have been affected. However, NSP found that one 

alternative associated with the purchase of a gagging device that could be used to close a 

stuck-open SG safety valve would be potentially cost-beneficial (NSP 2008). The evaluation of 

these SAMAs is discussed further in Section F.6.2.

NSP considered the potential plant improvements identified in the IPE and IPEEE in the 

identification of plant-specific candidate SAMAs for internal and external events, as summarized 

below.

As a result of the PINGP 1 and 2 IPE, nine modifications to plant procedures, operator training, 

or plant hardware were identified. These enhancements are listed in the Section F.5.1.5 of the 

ER. Based on information provided in the ER and in response to NRC staff RAIs (NSP 2008, 

2009a and 2009b), all but two of these items have been implemented by either procedure 

modifications, operator training revisions, or hardware modifications. The two unresolved items 

involve procedure and/or plant modifications related to internal flooding events, specifically, a 

procedure change to crosstie Cooling Water System Headers A and B in order to supply the 

MFW pumps’ lube oil coolers following a break in one of the headers (referred to as 

Enhancement 2), and modifications to promote water flow out of the Auxiliary Feedwater 

Pump/Instrument Air Compressor Room following a break in the Cooling Water System or to 

segregate the room into two compartments (referred to as Enhancement 3). For these items, 

the ER credits an engineering calculation (ENG-ME-148, Revision 0, “Cooling Water Header 

Pipe Failure Causing Flooding in the Auxiliary Feedwater Pump/Instrument Air Compressor 

Room”) for providing confidence that the probability of a double-ended guillotine break is 

negligible and that leak-before-break detection will provide sufficient warning for the 

accomplishment of mitigation actions. This calculation, in conjunction with the 1992 installation 

of 33 percent thicker walled piping, was provided as the present resolution for these internal 

flooding enhancements. The calculation and piping modification were also used as the bases for 

reducing the significance of the Cooling Water Header flood in the PRA. After reviewing the 
Appendix F

F-17

engineering calculation, the NRC staff noted that it used deterministic arguments to address a 

probabilistic pipe break frequency issue. The NRC staff also noted that two SAMAs, SAMA 6a 

(Segregate Flooding Zones) and SAMA 13 (Install Automatic Sump Pump for Zone 7 Auxiliary 

Building Flooding), are improvements that address Cooling Water floods and their significance 

could have been underestimated as a result of the above method. In response to a follow-up 

RAI, NSP stated that the method used to resolve these issues was not consistent with current 

PRA practices and that its use could have caused the value of Enhancements 2 and 3 to be 

understated. As a result, NSP has entered IPE Potential Enhancements 2 and 3 into their 

Corrective Action Program for further evaluation after the PRA has been updated with improved 

methodology for modeling pipe breaks (NSP 2009b).

Based on this information, the NRC staff concludes that the set of SAMAs evaluated in the ER, 

together with those identified in supplemental information to the ER and in response to NRC 

staff RAIs, addresses the major contributors in internal event CDF.

NSP did not identify PINGP 1 and 2-specific candidate SAMAs for seismic events. In the IPEEE 

analysis, a total of 10 potential enhancements were identified to address external events. These 

enhancements are:

• Add fire wrap or other fire barrier material to exposed control power cable for 

Bus 16.

• Add instructions to locally start the available roof exhaust fan to Fire Safety 

Procedure F5.

• Add instructions to manually open a suction supply valve to the 12 Auxiliary 

Feedwater pump on a fire in Fire Area 32.

• Ensure fire brigade training includes a discussion of the risk significance 

associated with manual fire suppression for control room and relay room 

fires.

• Ensure operator training includes a discussion of the risk significance 

associated with plant shutdown from outside the control room in accordance 

with Fire Safety Procedure F5.

• Ensure operator training includes a discussion of the risk significance 

associated with bleed and feed cooling of the RCS due to internal fires.

• Ensure operator training is implemented to perform DC panel switching in the 

battery and relay rooms for a fire in Fire Area 59.

• Verify cable separation between trains in the G-panel.

• Upgrade the anchorage for the main Cardox tank associated with the Relay 

Room automatic fire suppression system.

• Upgrade the battery and fuel oil day tank anchorages for the diesel driven fire 

water pump. 

The above list of potential plant improvements is primarily related to fire events and seismic/fire 

interactions. As noted in the ER, all identified improvements have either been implemented or 

otherwise resolved, and therefore were not considered further in the SAMA analysis.

The IPEEE seismic margin analysis identified 22 outliers, where each outlier represents one or 

more like components (NSP 1996, NSP 2000 and NRC 2001a). These were designated for 

resolution under the A-46 program. As stated in the NRC’s A-46 safety evaluation report, all A-
Appendix F

F-18

46 outliers were either resolved or scheduled for resolution by the May 1999 Unit 1 outage 

(NRC 1998b).

In addition to the 22 outliers discussed above, NSP identified several potential seismic outliers 

that were dispositioned through an analysis process described in the IPEEE that concluded that 

the impacted function was not required or could be recovered, or that an alternate means for 

performing the associated function was available. The outliers include: turbine-driven AFW 

pump trip and throttle valves, diesel generator fuel oil storage tanks 122 and 124, the boric acid 

transfer pumps, charging pumps 12 and 23, panel 117, cooling water pump 121, condensate 

storage tanks 11, 12 and 13, component cooling water pressure switches, and diesel-driven 

cooling water pump pressure switches. NRC staff requested that NSP demonstrate for these 

selected outliers that enhancing the ruggedness of the associated components is not costbeneficial. NSP provided a detailed discussion of each of the selected outliers. No additional 

SAMAs were identified as a result of this further evaluation. (NSP 2008). The NRC staff 

reviewed the rationale used to disposition each of these seismic-related outliers and found the 

rationale to be reasonable.

The NRC staff also noted that the PINGP 1 and 2 IPEEE seismic margin analysis found the 

component cooling water heat exchangers to have a HCLPF of 0.28g which is below the 0.3 g 

screening value. In response to a NRC request to assess whether increased seismic capacity 

would be cost-beneficial, NSP stated that the component cooling heat exchangers were 

considered to be very close to the 0.3g threshold, and were thus considered to be adequate. 

NSP also stated that the component cooling function which is to provide cooling to the RCP 

seals, can be accomplished by the Chemical and Volume Control System (CVCS) therefore 

reducing the significance of the heat exchanger seismic capacity (NSP 2008).

The NRC staff noted that the PINGP 1 and 2 IPEEE seismic margin analysis included a 

recommendation to restrain or remove wall hung ladders and scaffolding located near safety 

related equipment. In response to an NRC staff request for information regarding this 

recommendation, NSP stated that during a recent field walkdown it was noted that ladders are 

still located near safety-related equipment such as 4160 VAC Bus 25 and D2 and that an 

investigation determined that there was no clear guidance for the location and construction of 

ladder storage. NSP stated that this condition has been entered into the PINGP 1 and 2

Corrective Action Program to further investigate the issue and to determine whether current 

ladder storage standards are adequate (NSP 2008).

Based on the licensee’s efforts to identify and address seismic outliers and the expected cost 

associated with further seismic risk analysis and potential plant modifications, the NRC staff 

concludes that the opportunity for seismic-related SAMAs has been adequately explored and 

that it is unlikely that there are additional potentially cost-beneficial, seismic-related SAMA 

candidates. 

NSP did not identify PINGP 1 and 2-specific candidate SAMAs for fire events. In order to better 

understand the process used to identify fire-related SAMAs, the NRC staff requested that NSP 

demonstrate that no viable SAMA candidates exist for each fire scenario included in the IPEEE.

In response, NSP stated that the IPEEE fire analysis has not been updated, contains significant 

conservative assumptions, and does not include the plant modifications, procedure changes 

and changes in risk analysis methodology that have occurred in the twelve years since its 

completion. Notwithstanding the above considerations, NSP provided a list of additional SAMAs 

that specifically address the risk from internal fires. These SAMAs were either implemented 

(e.g., enhanced control of transient combustibles and ignition sources, enhanced fire brigade 

awareness, upgraded fire comportment barriers) or considered not to be cost-beneficial (e.g., 

relocate instrument air compressors out of the AFW pump rooms, re-route cables that currently 
Appendix F

F-19

run through risk significant fire areas). For each identified SAMA candidate, they provided a 

disposition that resulted in the elimination of these fire-related SAMAs from further consideration 

(NSP 2008). The NRC staff reviewed the rationale used to disposition each of these fire-related 

SAMAs and found the rationale to be reasonable.

The NRC staff concludes that the opportunity for fire-related SAMAs has been adequately 

explored and that it is unlikely that there are additional potentially cost-beneficial, fire-related 

SAMA candidates.

The NRC staff notes that the set of SAMAs submitted is not all inclusive, since additional, 

possibly even less expensive, design alternatives can always be postulated. However, the staff 

concludes that the benefits of any additional modifications are unlikely to exceed the benefits of 

the modifications evaluated and that the alternative improvements would not likely cost less 

than the least expensive alternatives evaluated, when the subsidiary costs associated with 

maintenance, procedures, and training are considered.

The NRC staff concludes that NSP used a systematic and comprehensive process for 

identifying potential plant improvements for PINGP 1 and 2, and that the set of SAMAs 

evaluated in the ER, together with those identified in response to the NRC staff inquiries, is 

reasonably comprehensive and therefore acceptable. This search included reviewing insights 

from the plant-specific risk studies, reviewing plant improvements considered in previous SAMA 

analyses, and using the knowledge and experience of its PRA personnel. While explicit 

treatment of external events in the SAMA identification process was limited, it is recognized that 

the prior implementation of plant modifications for seismic and fire events and the absence of 

external event vulnerabilities reasonably justifies examining primarily the internal events risk 

results for this purpose.

F.4. Risk Reduction Potential of Plant Improvements

NSP evaluated the risk-reduction potential of the nine remaining SAMAs that were applicable to 

PINGP 1 and 2. The SAMA evaluations were performed by using realistic assumptions with 

some conservatism. On balance, such calculations overestimate the benefit and are 

conservative.

For all of the SAMAs, NSP used model re-quantification to determine the potential benefits. The 

CDF and population dose reductions were estimated using the Rev. 2.2 (SAMA) model version 

of the PINGP 1 and 2 PRA. The changes made to the model to quantify the impact of the 

SAMAs are detailed in Section F.6 of Attachment F to the ER (NMC 2008). Table F-6 lists the 

assumptions considered to estimate the risk reduction for each of the evaluated SAMAs, the 

estimated risk reduction in terms of percent reduction in CDF and population dose, and the 

estimated total benefit (present value) of the averted risk. The estimated benefits reported in 

Table F-6 reflect the combined benefit in both internal and external events. The determination of 

the benefits for the various SAMAs is further discussed in Section F.6.

In the SAMA analysis submitted in the ER, NSP increased the benefit that was derived from the 

internal events model by a factor of 2 to account for the combined contribution from internal and 

external events. The NRC staff agrees with the licensee’s overall conclusion concerning the 

impact of external events and concludes that the licensee’s use of a multiplier of 2 is adequate.

This is discussed further in Section F.6.2.

Based on the description in the ER, the dominant internal flooding sequence (involving cooling 

water header rupture) would result in core damage to both units. In response to a NRC staff 

question, NSP explained that the dominant internal flooding sequences involved flooding of the 

695’ elevation of the Auxiliary Building from a rupture of a Cooling Water system header. If the 
Appendix F

F-20

operators fail to identify and isolate the rupture prior to submergence of the component water 

pumps, then residual heat removal pumps, containment spray pumps as well as motor control 

centers supporting the charging pumps and other safeguards equipment will be lost. This results 

in the loss of reactor coolant pump seal cooling and eventually leads to an unrecoverable RCP 

seal LOCA. As this flooding event impacts both units (NSP 2008), the NRC requested 

clarification as to the basis for the $2M per unit estimated cost for installation of flood barriers 

shown in Table F.5.3 of the ER. NSP stated that at least 22 (11 per unit) individual, customdesigned enclosures would be required and that the estimated cost for the design, fabrication, 

installation and maintenance of these enclosures could reach $200,000 each. In a follow-up 

question, staff requested an evaluation of a less extensive, alternative that would limit water 

damage to single unit. In response, NSP stated that the room impacted by this flood is located 

in the basement of the Auxiliary Building between the two units and the equipment within the 

room is not separated by unit. Therefore a wall or other flood-limiting barrier would not be 

practical.

The NRC staff has reviewed NSP’s bases for calculating the risk reduction for the various plant 

improvements and concludes that the rationale and assumptions for estimating risk reduction 

are reasonable and somewhat conservative (i.e., the estimated risk reduction is similar to or 

somewhat higher than what would actually be realized). Accordingly, the staff based its 

estimates of averted risk for the various SAMAs on NSP’s risk reduction estimates
Appendix F

F-21

Table F-6. SAMA Cost/Benefit Screening Analysis for PINGP 1 and 2 (a)

SAMA Modeling Assumptions Unit

% Risk Reduction Total Benefit ($)

Cost

($) per

Unit

CDF Population 

Dose

Using 7% 

discount 

rate

Using 3% 

discount 

rate (b)

2 - Install 

alternate 

cooling water 

supply

An independent, diverse, auto-start 

diesel-driven alternate cooling 

water pump was added to the 

models. Pump failure rates were 

assumed to be the same as 

existing pumps.

1 21.2 6.8 88,000 123,000 1.2M(c)

2 17.1 2.5 88,200 123,000

3 - Provide 

alternate flow 

path from 

RWST to 

charging 

pump station 

(d)

A bypass line for each unit that 

contains a normally closed, fail 

closed air-operated valve that 

opens on low VCT level was 

added. The valve was assumed 

to have no air dependency and to 

have a failure rate of a typical airoperated valve.

1 13.0 3.4 53,700 75,000 250K

2 10.7 1.3 54,900 76,700

5 - Install 

additional 

diesel-driven 

HPI pump

An independent, diverse, auto-start 

diesel-driven pump was added.

The pump was assumed to have 

no common cause coupling with 

the existing safety injection (SI) 

pumps. Pump failure rates were 

assumed to be the same as one 

of the existing diesel-driven 

cooling water pumps.

1 0.3 18.4 54,300 76,000 1.5M

2 0.8 12.6 159,000 223,000

9 - Analyze room 

heat-up for 

natural / 

forced 

circulation 

(Screenhous

e Ventilation)

The safeguards vertical cooling water 

pump (12, 121 and 22) were 

assumed to not fail due to 

Screenhouse Ventilation system 

failures.

1 10.7 3.4 45,000 62,700 62.5K

2 8.6 1.3 45,100 62,900

12 - Alternate 

component 

cooling water 

supply (e)

The cooling water upgrade from 

SAMA 2 has been performed, 

and an automatic means of 

supplying water on loss of 

component cooling flow using 

motor-operated valves was added 

with typical valve failure rates.

1 30.1 8.9 133,000 186,000 900K

2 25.2 8.2 216,000 302,000

15 - Provide 

portable DC 

power source 

A dedicated DC backup supply for 21 

AFW pump breaker control power 

was added with a typical battery 

failure on demand probability.

1 0 0 0 0 130K

2 2.8 0.3 13,800 19,300

19 - Upgrade 

RHR suction 

piping and install 

containment 

isolation valve 

A normally open, automatic isolation 

motor-operated valve was added to 

the common suction piping to both 

RHR pumps and assumed to have 

typical MOV failure rates. The RHR 

pumps were assumed to be 

unavailable for recovery following 

successful operation of the MOV.

1 0.2 12.6 43,200 60,500 700K

2 0.1 4.5 43,300 60,500
Appendix F

F-22

SAMA Modeling Assumptions Unit

% Risk Reduction Total Benefit ($)

Cost

($) per

Unit

CDF Population 

Dose

Using 7% 

discount 

rate

Using 3% 

discount 

rate (b)

19a – Provide a 

reliable backup 

water source for 

replenishing the 

RWST 

An operator action performed from 

the control room to refill the RWST 

was added with a failure rate of 0.1. 

Flow path valves were added and 

assumed to have typical failure 

rates.

1 34.0 18.4 236,000 330,000 1.9M

2 30.8 27.8 666,000 930,000 1.9M

20 - Close low 

head injection 

MOVs to prevent 

RCS backflow to 

safety injection 

system 

The four low head reactor vessel 

injection MOVs are assumed to be 

closed and to alarm if they fail to 

remain closed. Mission time for 

catastrophic failure time is 24 hours 

as double-check valve design limits 

exposure to high RCS pressure. 

Typical MOV failure rates are 

assumed.

1 0.1 11.3 38,600 53,900 268K (f)

2 0.1 4.1 39,100 54,600 220K (f)

22 - Provide 

compressed air 

backup for 

instrument air to 

containment 

The air supply to the PORVs will 

not fail to provide sufficient air for 

bleed and feed operation.

1 .4 1.4 11,000 15,400 39K

2 1.8 2.2 48,400 67,700

(a) SAMAs in bold are potentially cost-beneficial.

(b) Benefit values for 3 percent case reflect corrections provided by NSP in response to RAI 6.e 

(NSP 2008).

(c) Implementation cost reflects correction provided by NSP in response to RAI 6.b (NSP 2008).

(d) SAMA 3 was found to be potentially cost-beneficial as a result of a sensitivity analysis on the 

impact of an increased likelihood of an induced SGTR. See Section G.6.2 (NSP 2009b).

(e) Benefit is based on prior implementation of SAMA 2, with SAMA 12 design requirements also 

incorporated. SAMA 2 upgrades the existing diesel-driven fire pump such that it can supply both 

the needs of the Fire Protection System and the Cooling Water System (ER Section F.6.1, 

Assumption 1). SAMA 12 assumes that this upgrade is in place such that Fire Protection System 

is a viable source of alternate water (ER Section F.6.5, Assumption 1).

(f) Implementation cost reflects correction provided by NSP in response to RAI 6.c (NSP 2009a).

F.5. Cost Impacts of Candidate Plant Improvements

NSP estimated the costs of implementing the nine candidate SAMAs through the application of 

engineering judgment, use of other licensees’ estimates for similar improvements, and 

development of site-specific cost estimates. The cost estimates do not include the cost of 

replacement power during extended outages required to implement the modifications. In 

response to an RAI, NSP stated that the implementation costs also did not include contingency 

costs associated with unforeseen implementation obstacles, nor do they include any inflation 

adjustments (NSP 2008). Neglecting these factors is conservative.

The NRC staff reviewed the bases for the applicant’s cost estimates. For certain improvements, 

the staff also compared the cost estimates with estimates developed elsewhere for similar 

improvements, including estimates developed as part of other licensees’ analyses of SAMAs for 

operating reactors and advanced light-water reactors. The NRC staff reviewed the costs and 

found them to be reasonable, and generally consistent with estimates provided in support of 

other plants’ analyses.
Appendix F

F-23

The NRC staff requested additional information regarding the estimated costs for certain 

SAMAs, as summarized below.

• For SAMA 2 (Install alternate cooling water supply), the NRC staff requested 

clarification on the $300K implementation cost for each unit. In response, 

NSP stated that the estimate was for procedure changes as implementation 

of this SAMA credits a potable fire pump connected to the cooling water 

system and utilizes existing connections. NSP further noted that additional 

analysis now indicates that the portable fire pump capacity was not adequate 

and that a diesel-driven pump would be required with an estimated cost of 

$2.4 million shared between the two units. This estimate is stated as being 

comparable to cost of a similar installation at another power plant (NSP 2008) 

• For SAMA 6a (Segregate Auxiliary Building flooding zones), the NRC staff 

requested additional information on the description of the proposed 

modification to better understand the cost estimate of $2M per unit. In 

response, NSP stated that the modification would have to consist of a series 

of enclosures that surround individual equipment. Some enclosures would 

only consist of walls to protect from rising water while others would need to 

provide full covered enclosures to protect from spray. At least 22 (11 per unit) 

individual, custom-designed enclosures would be required. In response to a 

follow-up question to consider a less extensive alternative that would limit 

water damage to the systems, structures and components for a single unit, 

NSP stated that the equipment is separated not by unit, but by train.

Therefore, a wall or other flood-limiting barrier to protect one unit is not 

practical (NSP 2008 and 2009)

• For SAMA 20 (Close low head injection MOVs to prevent RCS backflow to 

safety injection system), staff requested clarification of the $100K life-cycle 

cost component of the cost estimate, since this SAMA simply changes the 

operation of an existing valve. In response, NSP stated that additional review 

revealed the life-cycle cost would be inherent to maintaining these valves 

whether the valves are normally open or closed. Therefore, NSP removed the 

$100K life cycle cost from the cost estimate for SAMA 20 (NSP 2009a). Table 

F-6 reflects this corrected value.

• The NRC staff also requested clarification as to the treatment of candidate 

SAMAs that have a positive risk benefit to both units. In response, NSP 

stated that the costs were evenly apportioned between the two units (NSP 

2009a). This is appropriate since the risk reduction benefit for each unit is 

determined separately.

The NRC staff reviewed the additional information provided by NSP and found it to be 

reasonable. The NRC staff concludes that the cost estimates provided by NSP are sufficient 

and appropriate for use in the SAMA evaluation.

F.6. Cost-Benefit Comparison

NSP’s cost-benefit analysis and the NRC staff’s review are described in the following sections.
Appendix F

F-24

F.6.1. NSP’s Evaluation

The methodology used by NSP was based primarily on NRC’s guidance for performing costbenefit analysis, i.e., NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook 

(NRC 1997a). The guidance involves determining the net value for each SAMA according to the 

following formula:

Net Value = (APE + AOC + AOE + AOSC) – COE where,

APE = present value of averted public exposure ($)

AOC = present value of averted offsite property damage costs ($)

AOE = present value of averted occupational exposure costs ($)

AOSC = present value of averted onsite costs ($)

COE = cost of enhancement ($).

If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 

benefit associated with the SAMA, and it is not considered cost-beneficial. NSP’s derivation of 

each of the associated costs is summarized below.

NUREG/BR-0058 was revised in 2004 to reflect the agency's policy on discount rates. Revision 

4 of NUREG/BR-0058 states that two sets of estimates should be developed: one at 3 percent 

and one at 7 percent (NRC 2004b). NSP provided both sets of estimates (NMC 2008).

The APE costs were calculated by using the following formula:

Averted Public Exposure (APE) Costs

APE = Annual reduction in public exposure (∆person-rem per year)

× monetary equivalent of unit dose ($2000 per person-rem)

× present value conversion factor (15.04 based on a 20-year period with a

3-percent discount rate).

As stated in NUREG/BR-0184 (NRC 1997a), it is important to note that the monetary value of 

the public health risk after discounting does not represent the expected reduction in public 

health risk due to a single accident. Rather, it is the present value of a stream of potential losses 

extending over the remaining lifetime (in this case, the renewal period) of the facility. Thus, it 

reflects the expected annual loss due to a single accident, the possibility that such an accident 

could occur at any time over the renewal period, and the effect of discounting these potential 

future losses to present value. For the purposes of initial screening, which assumes elimination 

of all severe accidents due to internal events, NSP calculated an APE of approximately $88,000 

for Unit 1 and $254,000 for Unit 2 for the 20-year license renewal period.

The AOCs were calculated by using the following formula:

Averted Offsite Property Damage Costs (AOC)

AOC = Annual CDF reduction

× offsite economic costs associated with a severe accident (on a per-event basis)

× present value conversion factor.

For the purposes of initial screening, which assumes all severe accidents due to internal events 

are eliminated, NSP calculated an annual offsite economic risk of about $16,000 for Unit 1 and 

$63,000 for Unit 2 based on the Level 3 risk analysis. This results in a discounted value of 

approximately $238,000 for Unit 1 and $953,000 for Unit 2 for the 20-year license renewal 

period.
Appendix F

F-25

The AOE costs were calculated by using the following formula:

Averted Occupational Exposure (AOE) Costs

AOE = Annual CDF reduction

× occupational exposure per core damage event

× monetary equivalent of unit dose

× present value conversion factor.

NSP derived the values for averted occupational exposure from information provided in Section 

5.7.3 of the regulatory analysis handbook (NRC 1997a). Best estimate values provided for 

immediate occupational dose (3300 person-rem) and long-term occupational dose (20,000 

person-rem over a 10-year cleanup period) were used. The present value of these doses was 

calculated by using the equations provided in the handbook in conjunction with a monetary 

equivalent of unit dose of $2000 per person-rem, a real discount rate of 3 percent, and a time 

period of 20 years to represent the license renewal period. For the purposes of initial screening, 

which assumes all severe accidents due to internal events are eliminated, NSP calculated an 

AOE of approximately $6,100 for Unit 1 and $7,500 for Unit 2 for the 20-year license renewal 

period.

Averted onsite costs (AOSC) include averted cleanup and decontamination costs (ACC) and 

averted power replacement costs. Repair and refurbishment costs are considered for 

recoverable accidents only and not for severe accidents. NSP derived the values for AOSC 

based on information provided in Section 5.7.6 of NUREG/BR-0184, the regulatory analysis 

handbook (NRC 1997a).

Averted Onsite Costs (AOSC)

NSP divided this cost element into two parts: the onsite cleanup and decontamination cost, also 

commonly referred to as averted cleanup and decontamination costs, and the replacement 

power cost.

Averted cleanup and decontamination costs were calculated by using the following formula:

ACC = Annual CDF reduction

× present value of cleanup costs per core damage event

× present value conversion factor.

The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 

the regulatory analysis handbook to be $1.5 x 109 (undiscounted). This value was converted to 

present costs over a 10-year cleanup period and integrated over the term of the proposed 

license extension. For the purposes of initial screening, which assumes all severe accidents due 

to internal events are eliminated, NSP calculated an ACC of approximately $191,000 for Unit 1 

and $235,000 for Unit 2 for the 20-year license renewal period.

Long-term replacement power costs (RPC) were calculated using the following formula:

RPC = Annual CDF reduction

× present value of replacement power for a single event

× factor to account for remaining service years for which replacement power is

required

× reactor power scaling factor

NSP based its calculations on the value of 560 megawatt electric (MW(e)). Therefore, NSP 

applied a power scaling factor of 560/910 (the ratio of the actual power level to the “generic” 

power plant level in NUREG/BR-0184) to determine the replacement power costs. For the 

purposes of initial screening, which assumes all severe accidents due to internal events are 
Appendix F

F-26

eliminated, NSP calculated an RPC of approximately $33,000 for Unit 1 and $41,000 for Unit 2, 

and an AOSC of $224,000 for Unit 1 and $276,000 for Unit 2.

By using the above equations, NSP estimated the total present dollar value equivalent 

associated with completely eliminating severe accidents due to internal events at PINGP 1 and 

2 to be about $557,000 for Unit 1 and $1.49 million for Unit 2. The higher baseline risk for Unit 2 

is attributed to the higher CDF and LERF resulting from the fact that Unit 2 has not yet replaced 

its steam generators. To account for additional risk reduction in external events, NSP doubled 

this value (to $1.11 million for Unit 1 and $2.98 million for Unit 2) to provide the modified 

maximum averted cost risk (MMACR), which represents the dollar value associated with 

completely eliminating all internal and external event severe accident risk at PINGP 1 and 2.

The total site MMACR for PINGP 1 and 2 is then $4.09 million.

If the implementation costs for a candidate SAMA were greater than the MMACR of $1.11 

million for Unit 1 and $2.98 million for Unit 2, then the SAMA was screened from further 

consideration. A more refined look at the costs and benefits was performed for the remaining 

SAMAs. If the implementation costs for a candidate SAMA exceeded the calculated benefit, the 

SAMA was considered not to be cost-beneficial. In the baseline analysis contained in the ER 

(using a 3 percent discount rate), NSP identified one potentially cost-beneficial SAMA for Unit 1 

and two potentially cost-beneficial SAMAs for Unit 2. The potentially cost-beneficial SAMAs are:

NSP’s Results

• SAMA 9 (Unit 1 and Unit 2) – Implement procedure or plant modification to 

improve ventilation for safeguards equipment in the Screenhouse. This would 

be achieved by either performing a best-estimate room heat-up analysis to 

show that procedural practices (opening doors, installing portable fans) would 

allow safeguards cooling water pumps to run for at least 24 hours without 

forced ventilation following a loss of the safeguard ventilation system serving 

those rooms, or improving Screenhouse ventilation reliability via hardware 

modifications.

• SAMA 22 (Unit 2 only) – Provide compressed air backup for instrument air to 

containment. This would be achieved by either qualifying the existing 

accumulator air supply for bleed and feed cooling when the normal supply of 

instrument air to the PORVs is unavailable, or providing a backup to the 

accumulators to support feed and bleed operation.

NSP performed additional analyses to evaluate the impact of parameter choices and 

uncertainties on the results of the SAMA assessment (NMC 2008). If the benefits are based on 

use of the 95th percentile CDF results rather than the point estimates for CDF, one additional 

SAMA candidate was determined to be potentially cost-beneficial for Unit 1. This is SAMA 22, 

which had already been shown to be cost-beneficial for Unit 2.

In response to NRC staff inquiries regarding the treatment of consequential SGTR in the 

baseline PRA, the approach used to estimate uncertainty, and the consideration of lower cost 

alternatives, NSP identified three additional potentially cost-beneficial SAMAs. In addition, in 

response to NRC questions regarding modeling of internal floods, NSP entered two 

unimplemented IPE enhancements into the PINGP 1 and 2 Corrective Action Program for 

further evaluation after the PRA has been updated with improved methodology for modeling 

pipe breaks. 

The potentially cost-beneficial SAMAs and NSP’s plans for further evaluation of these SAMAs 

are discussed in more detail in Section F.6.2.
Appendix F

F-27

F.6.2. Review of NSP’s Cost-Benefit Evaluation

The cost-benefit analysis performed by NSP was based primarily on NUREG/BR-0184 (NRC 

1997a) and was implemented consistent with this guidance.

SAMAs identified primarily on the basis of the internal events analysis could provide benefits in 

certain external events, in addition to their benefits in internal events. To account for the 

additional benefits in external events, NSP multiplied the internal event benefits for each internal 

event SAMA by a factor of 2. Potential benefits in external events were estimated in this manner 

since the external events models are generally less detailed than the internal events models 

and do not lend themselves to quantifying the benefits of the specific plant changes associated 

with internal event SAMAs. For example, the benefits of a procedure change associated with an 

important internal event sequence cannot be readily assessed using the seismic risk model if 

that operator action or system is not represented in the seismic risk model. The use of a 

multiplier on the benefits obtained from the internal events PRA to incorporate the impact of 

external events implicitly assumes that each SAMA would offer the same percentage reduction 

in external event CDF and population dose as it offers in internal events. While this provides 

only a rough approximation of the potential benefits, such an adjustment was considered 

appropriate given the risk contribution from external events relative to internal events and the 

lack of information on which to base a more precise risk reduction estimate for external events.

As the IPEEE results indicate an external events contribution that is about 4 to 5 times the 

internal events CDF, additional information and analysis was provided by NSP in response to 

NRC staff questions regarding the basis for the use of a multiplier of 2 for external events. As 

discussed in Section F.2.2, NSP demonstrated that the PINGP 1 and 2 fire risk would be in the 

range of 1 x 10-5 per year rather than the fire CDF of about 5 x 10-5 per year from the IPEEE.

NSP also estimated the seismic contribution by using what they referred to as a bounding 

“Simplified Hybrid Method” to quantify the results of the seismic margin analysis. This method 

resulted in a CDF of 7.8 x 10-6 per year. A corresponding NRC staff estimate using updated 

USGS seismic hazard information is 2.5 x 10-6 per year. For other external hazards (i.e., high 

winds, tornadoes, external flooding, transportation and nearby industrial facility accidents), NSP 

stated that PINGP 1 and 2 meets the applicable Standard Review Plan requirements, and 

therefore has an acceptably low risk with respect to these hazards. In conclusion, NSP stated 

that no higher multiplier is believed to be warranted (NSP 2008). In view of the additional 

justification provided by NSP, including the remaining conservatism in the external events CDF, 

and the licensee’s further evaluation of the impacts of uncertainty on SAMA results (discussed 

below), the NRC staff agrees that the internal and external event CDF values would be 

comparable, and that use of a multiplier of 2 for external events is reasonable for the purposes 

of the SAMA evaluation.

NSP considered the impact that possible increases in benefits from analysis uncertainties would 

have on the results of the SAMA assessment. In the ER, NSP presents the results of an 

uncertainty analysis of the internal event CDF for Units 1 and 2. The NSP approach quantified 

the Level 1 model uncertainty and uncertainty multiplier for each SAMA. (In previous license 

renewal uncertainty analyses, licensees determined and applied a single uncertainty multiplier 

based on the uncertainty distribution in the baseline risk model.) In response to a NRC staff 

question on the uncertainty analysis, NSP provided additional justification on their approach.

However, in reviewing the application of their uncertainty approach, NSP did find that the 95th

percentile result for each SAMA had been incorrectly divided by the baseline CDF value as 

opposed to the estimated CDF value for the SAMA. Corrected uncertainty multipliers were 

provided (NSP 2008). The factor by which the 95th percentile CDFs exceed the point estimate 

CDFs ranged from 1.8 to 2.9 over the set of SAMAs (NMC 2008).
Appendix F

F-28

NSP reexamined the initial set of SAMAs to determine if any additional Phase I SAMAs would 

be retained for further analysis if the benefits (and MMACR) were increased by the 95th

percentile uncertainty factor for each SAMA. Five such Phase I SAMAs were identified: SAMA 1 

- Automate the swap-over of ECCS from the RWST to the containment sump, SAMA 10 -

Automate the transfer of charging pump suction from the VCT to the RWST on low VCT level, 

SAMA 17 - Provide a bypass line around the RHR Loop B return valve to reduce the risk 

associated with failure of the return valve to open, SAMA 19a - Upgrade equipment and 

procedures for replenishing RWST inventory from a large water source, and SAMA 21 -

Increase the reliability of PORV closure. These SAMAs were further evaluated as described 

below.

NSP also considered the impact on the Phase II screening if the estimated benefits were 

increased by the 95th percentile uncertainty factor for each SAMA. NSP reported in the ER that 

one additional SAMA could be cost-beneficial for Unit 1. This additional SAMA is SAMA 22, 

which was already shown to be cost-beneficial for Unit 2 in the baseline analysis. However, the 

results of the revised uncertainty assessment show that SAMA 19a (Upgrade equipment and 

procedures for replenishing RWST inventory from a large water source) is also potentially costbeneficial for Unit 2. SAMA 19a which improves the SGTR mitigation capability is not costbeneficial for Unit 1 as this unit had its steam generators replaced in 2004. NSP has entered 

SAMA 19a into the PINGP Corrective Action Program for further evaluation for Unit 2 (NSP 

2008 and 2009a). The NRC staff finds that the updated uncertainty analysis and the application 

of this analysis to the SAMA screening process to be adequate for the identification of potential 

SAMAs.

The NRC noted that, for certain SAMAs considered in the ER, there may be lower-cost 

alternatives that could achieve much of the risk reduction at a lower cost. Several of these 

alternatives were evaluated by NSP subsequent to the ER, and described in the supplemental 

information to the ER (NSP 2008). These alternatives include:

• Procedure for manually controlling the degree of SG depressurization and 

reclosing the SG PORVs in the event core damage is imminent

• Procedure for enhancing manual operation of turbine-driven Auxiliary 

Feedwater pumps including the consideration of alternate water sources and 

operator aids for using local flow indication

• Procedure and equipment for using a portable pump to provide Feedwater to 

the SGs with suction from either the external fire ring header or intake canal

• Procedure for recovering emergency diesel generators D-1 and D-2 by 

supplying alternate cooling from well water

• Reconfiguring the non-safety main feedwater loads to be powered from DC 

Bus B (as an alternative to SAMA 15)

• Modifying the charging pumps electrical connections to enable re-powering 

from alternate 480 power supply using pre-staged cables

• Installing a connection flange and valve on safety injection pump flow test 

return line to the refueling water storage tank to enable cross-connection of 

SI pumps to AFW piping

• Modifying the charging and volume control system to allow cross-tie of the 

charging pumps from the opposite unit
Appendix F

F-29

• Purchase of a gagging device that could be used to close a stuck-open SG 

safety valve on the ruptured steam generator prior to core damage in SGTR 

events

In response, NSP indicated that for some of the above candidate SAMAs plant guidance 

currently exists, and for others, their implementation would not be cost-beneficial. The 

disposition is summarized as follows. Procedures for manually controlling the degree of SG 

depressurization, manual operation of the turbine-driven pumps, use of a portable pump to 

provide feedwater to the SGs, and the recovery of cooling water for emergency diesel 

generators D-1 and D-2 were stated as already being in place. The alternate to SAMA 15 was 

estimated to have a higher implementation cost than SAMA 15 as it would involve modifications 

to a larger set of components. The alternative that suggested re-powering the charging pumps 

using alternate 480V power and pre-staged cables was stated as not being cost-beneficial due 

to the ability to cross-tie the 4kV buses between units, the availability of dedicated EDGs for 

each 4kV safeguards bus, and the design differences between each unit’s EDG sets which 

limits the likelihood of common cause failure of all the site EDGs. The alternative of enabling 

cross-connection of SI to AFW pumps was stated as likely to be ineffective as such a 

connection would require a long length of hose able to withstand high pressures and that other 

alternative means have already been implemented. The alternative to modify the charging and 

volume control system to allow it to be cross-tied from the opposite unit was stated as having an 

implementation cost that would be greater than that of SAMA 3 (Provide alternate flow path from

RWST to charging pump suction) as the piping for this alternative is longer. However, NSP 

concluded that the last alternative identified above, purchase of a gagging device for closing a 

stuck-open steam generator safety valve, may be cost-beneficial at PINGP 1 and 2 (for both 

units). NSP has entered this SAMA into the PINGP Corrective Action Program for a more 

detailed examination of its viability and implementation cost (NSP 2008).

As discussed in Section F.2.2, the NRC staff could not clearly establish the modeling approach 

used to assess the likelihood of a thermally-induced SGTR following core damage in the current 

PRA. In response to an RAI, NSP stated that the treatment of induced SGTR events follows the 

guidance of WCAP-16341-P, “Simplified Level 2 Modeling Guidelines.” However, this guidance 

has not been submitted to or reviewed by the NRC. NSP stated that all accident sequences 

where core damage occurs at high reactor pressure and the steam generators are dry at the 

time of core damage are assumed to have the potential to lead to pressure-induced SGTR. In 

addition, all high reactor pressure, dry steam generator sequences in which the RCS is not 

depressurized prior to vessel failure are assumed to have the potential to lead to temperatureinduced SGTR. In order to progress to an induced SGTR, NSP assumed that the secondary 

side must be depressurized, either through failure of a relief valve upstream of the MSIV, or 

through a main steam or feedwater line break. However, implementation details were not 

provided or reviewed.

In order to demonstrate the sensitivity of the SAMA analysis results to this issue, the NRC staff 

requested that NSP assess the impact on results if an induced SGTR conditional probability of 

0.25 were used in the baseline analysis (i.e., a 0.25 probability of an induced SGTR given core 

damage with high primary side pressure and a dry secondary side at low pressure). A 

conditional probability of 0.25 is consistent with the base case results of an NRC study of 

induced SGTR events documented in NUREG-1570 (NRC 1998c) and cited in the ASME PRA 

Standard (ASME 2002). NSP’s sensitivity analysis identified one additional cost-beneficial 

SAMA. i.e., SAMA 3 - Provide alternate flow path from RWST to charging pump suction.

Although NSP stated that it does not feel the 0.25 conditional probability assumption is valid for 

Prairie Island, they agreed to add SAMA 3 to the list of SAMAs that will be further evaluated for 

possible implementation (NSP 2009b).
Appendix F

F-30

As discussed in Section F.3.2, two unimplemented IPE enhancements were found to have been 

inappropriately dismissed, i.e., IPE Enhancement 2 - Procedure change to crosstie Cooling 

Water System Headers A and B in order to supply the MFW pumps’ lube oil coolers following a 

break in one of the headers, and IPE Enhancement 3 - Modifications to promote water flow out 

of the Auxiliary Feedwater Pump/Instrument Air Compressor Room following a break in the 

Cooling Water System or to segregate the room into two compartments. As a result, NSP has 

entered IPE Enhancements 2 and 3 into their Corrective Action Program for further evaluation 

after the PRA has been updated with improved internal flood methodology.

Finally, as discussed in Section F.3.2, one previously identified IPEEE improvement associated 

with restraining wall hung ladders was also found to not have been implemented. As a result, 

NSP has entered the ladder storage issue into their Corrective Action Program.

The NRC staff concludes that, with the exception of the potentially cost-beneficial SAMAs 

discussed above, the costs of the SAMAs evaluated would be higher than the associated 

benefits.

F.7. Conclusions

NSP compiled a list of 25 SAMAs based on a review of the most significant basic events from 

the plant-specific PRA, insights from the plant-specific IPE and IPEEE, and Phase II SAMAs 

from license renewal activities for other plants. An initial screening removed SAMA candidates 

that (1) were not applicable at PINGP 1 and 2 because of design differences, (2) had already 

been implemented at PINGP 1 and 2, (3) had no significant benefit, or had benefits which have 

been achieved by other means, or (4) required extensive changes that would involve 

implementation costs known to exceed any possible benefit (i.e., more than $1.11 million for 

Unit 1 and $2.98 million for Unit 2). Based on this screening, sixteen SAMAs were eliminated, 

leaving nine candidate SAMAs for evaluation.

For the remaining SAMA candidates, a more detailed evaluation was performed as shown in 

Table F-6. The cost-benefit analyses in the ER showed that two SAMA candidates were 

potentially cost-beneficial in the baseline analysis (SAMA 9 for Units 1 and 2, and SAMA 22 for 

Unit 2). NSP performed additional analyses to evaluate the impact of parameter choices and 

uncertainties on the results of the SAMA assessment. As a result, SAMA 22 was identified as 

potentially cost-beneficial for Unit 1. (This SAMA was already shown to be cost-beneficial for 

Unit 2.) Based on additional analysis, three additional SAMAs were identified as potentially costbeneficial, i.e., SAMA 3 - provide alternate flow path from RWST to charging pump suction (for 

Units 1 and 2), SAMA 19a - provide a reliable backup water source for replenishing the RWST 

(for Unit 2), and a SAMA regarding purchase of a gagging device for closing a stuck-open 

steam generator safety valve in SGTR events (for Units 1 and 2). NSP has indicated that these 

potential cost-beneficial SAMAs have been entered into the PINGP 1 and 2 Corrective Action 

Program to be further evaluated for possible implementation (NSP 2009a and 2009b). NSP has 

also indicated that as a result of an identified internal flood modeling limitation, two internal flood 

related enhancements previously identified in the IPE have also been entered into the 

Corrective Action Program for further evaluation after the PRA has been updated with improved 

methodology for modeling pipe breaks (NSP 2009b). Additionally, the lack of clear guidance for 

the location and construction of ladder storage has been entered into the PINGP 1 and 2

Corrective Action Program to further investigate the issue and to determine whether current 

ladder storage standards are adequate for seismic events (NSP 2008).

The NRC staff reviewed the NSP analysis and concluded that the methods used and the 

implementation of those methods were sound. The treatment of SAMA benefits and costs 

support the general conclusion that the SAMA evaluations performed by NSP are reasonable 
Appendix F

F-31

and sufficient for the license renewal submittal. Although the treatment of SAMAs for external 

events was somewhat limited, the likelihood of there being cost-beneficial enhancements in this 

area was minimized by improvements that have been realized as a result of the IPEEE process, 

and inclusion of a multiplier to account for external events. 

The NRC staff concurs with NSP’s identification of areas in which risk can be further reduced in 

a cost-beneficial manner through the implementation of the identified, potentially cost-beneficial 

SAMAs. Given the potential for cost-beneficial risk reduction, the staff agrees that further 

evaluation of these SAMAs by NSP is warranted. However, these SAMAs do not relate to 

adequately managing the effects of aging during the period of extended operation. Therefore, 

they need not be implemented as part of license renewal which is submitted pursuant to Title 10 

of the Code of Federal Regulations, Part 54, “Requirements for Renewal of Operating Licenses 

for Nuclear Power Plants” (10 CFR Part 54).

F.8. References

10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

Protection Regulations for Domestic Licensing and Related Regulatory Functions.”

10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.” 

ASME (American Society of Mechanical Engineer). 2002. “Standard for Probabilistic Risk 

Assessment for Nuclear Power Plant Applications,” ASME RA-S-2002, April 5, 2002.

EPRI (Electric Power Research Institute). 1991. A Methodology for Assessment of Nuclear 

Power Plant Seismic Margin, EPRI NP-6041-SL, Revision 1, Palo Alto, CA, August 1991.

Kennedy, Robert P. 1999. “Overview of Methods for Seismic PRA and Margin Analysis 

Including Recent Innovations”. Proceedings of the OECD-NEA Workshop on Seismic Risk, 

Tokyo, Japan, August 1999.

NMC (Nuclear Management Company, LLC). 2008. Prairie Island Nuclear Generating Plant, 

Units 1 and 2, License Renewal Application, Appendix E – Applicant’s Environmental Report, 

License Renewal Operating Stage. Redwing, Minnesota. April 2008. ADAMS Nos. 

ML081130677, ML081130681, and ML081130684.

NRC (U.S. Nuclear Regulatory Commission). 1990. Severe Accident Risks: An Assessment for 

Five U.S. Nuclear Power Plants. NUREG-1150, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 1991. Procedural and Submittal Guidance for the 

Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities.

NUREG-1407, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 1997c. Individual Plant Examination Program: 

Perspectives on Reactor Safety and Plant Performance. NUREG-1560, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 1997a. Regulatory Analysis Technical Evaluation 

Handbook. NUREG/BR-0184, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 1997b. Staff Evaluation of the Prairie Island 

Nuclear Generating Plant Individual Plant Examination (IPE) Submittal – Internal Event. Letter 

to Northern States Power Co., May.

NRC (U.S. Nuclear Regulatory Commission). 1998a. Code Manual for MACCS2: User’s-Guide. 

NUREG/CR-6613, Volume 1, SAND 97-0594. May 1998.
Appendix F

F-32

NRC (U.S. Nuclear Regulatory Commission). 1998b. Resolution of Unresolved Safety Issue 

(USI) A-46 for Prairie Island Nuclear Generating Plant, Units 1 and 2 (TAC NOS M69474 and 

M69475). Letter to Northern States Power Co., August 5, 1998.

NRC (U.S. Nuclear Regulatory Commission). 1998c. Risk Assessment of Severe AccidentInduced Steam Generator Tube Rupture. NUREG-1570, March 1998.

NRC (U.S. Nuclear Regulatory Commission). 2001a. Perspectives Gained From the Individual 

Plant Examination of External Events (IPEEE) Program. NUREG-1742, Vol. 2, Washington, 

D.C.

NRC (U.S. Nuclear Regulatory Commission). 2001b. Prairie Island Nuclear Generating Plant, 

Units 1 and 2 – Review of Individual Plant Examination of External Events (IPEEE) (TAC Nos.

M83663 and M83664). Letter to NMC, May 29, 2001.

NRC (U.S. Nuclear Regulatory Commission). 2003. SECPOP2000: Sector Population, Land 

Fraction, and Economic Estimation Program. NUREG/CR-6525, Rev. 1, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 2004a. An Approach for Determining the 

Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, 

Regulatory Guide 1.200 for Trial Use. (February 2004).

NRC (U.S. Nuclear Regulatory Commission). 2004b. Regulatory Analysis Guidelines of the U.S. 

Nuclear Regulatory Commission. NUREG/BR-0058, Rev. 4, Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission). 2008a. Request for Additional Information for the 

Review of the Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application 

(TAC Nos. MD8513 and MD8514). Letter to NMC, October 23, 2008.

NRC (U.S. Nuclear Regulatory Commission). 2008b. Request for Additional Information for the 

Review of the Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application 

(TAC Nos. MD8513 and MD8514). Letter to NMC, December 24, 2008.

NSP (Northern States Power Company). 1994. Prairie Island Nuclear Generating Plant 

Individual Plant Examination (IPE), NSPLMI-94001, Rev. 0, March 1. 

NSP (Northern States Power Company). 1996. PINGP Individual Examination of External 

Events (IPEEE), NSPLMI-96001, December 14, 1996.

NSP (Northern States Power Company). 1998. PINGP Individual Examination of External 

Events (IPEEE), NSPLMI-96001, Rev. 1, October 19, 1998.

NSP (Northern States Power Company). 2000. Response to Request for Additional Information 

Regarding Report NSPLMI-96001, Individual Plant Examination of External Events (IPEEE), 

Letter to NRC, February, 28 2000.

NSP (Northern States Power Company – Minnesota). 2008. Letter from M. Wadley, Site Vice 

President, Northern States Power Company – Minnesota, to U.S. Nuclear Regulatory 

Commission. Subject: Response to NRC Request for Additional Information Dated October 23, 

2008 Regarding Application for Renewed Operating Licenses. November 21, 2008. ADAMS No. 

ML083370505.

NSP (Northern States Power Company – Minnesota). 2009a. Letter from M. Wadley, Site Vice 

President, Northern States Power Company – Minnesota, to U.S. Nuclear Regulatory 

Commission. Subject: Response to NRC Requests for Additional Information Dated December 

24, 2008 Regarding Application for Renewed Operating Licenses. January 23, 2009. ADAMS 

No. ML090260290.
Appendix F

F-33

NSP (Northern States Power Company – Minnesota). 2009b. Letter from M. Wadley, Site Vice 

President, Northern States Power Company – Minnesota, to U.S. Nuclear Regulatory 

Commission. Subject: Supplemental Information Regarding Application for Renewed Operating 

Licenses. March 4, 2009. ADAMS No. ML090690684.

SQUG (Seismic Qualification Users Group). 1992. Generic Implementation Procedure (GIP) for 

Seismic Verification of Nuclear Plant Equipment, Revision 2, Corrected, February 14, 1992

USCB (U.S. Census Bureau). 2000. “Census 2000 Summary File 1 (SF 1) – 100 Percent Data.” 

Available URL: http://www.census.gov/Press-Release/www/2001/SumFile1.html.

USGS (U.S. Geological Survey). 2008. Documentation for the 2008 Update of the U. S. National 

Seismic Hazard Maps, Open-File Report 2008-1128.

Index-1

INDEX

accidents.............................................................................xix; 4-48, 4-53, 4-65; 5-1 to 5-3, 5-5, 

5-7 to 5-8; 8-37 to 8-38; A-158, 

A-163; B-9; F-4, F-9, F-11, F-25 to 

F-28

Advisory Council on Historic Preservation (ACHP)..............1-7, 1-9; 4-36; A-275; D-1

aesthetic .............................................................................xviii; 2-46, 2-54; 3-2; 4-32, 4-42; 

8-11, 8-20 to 8-21, 8-28, 8-37; B-90

alternatives .........................................................................iii, xix to xx; 1-5; 2-37; 4-21; 5-2 to 

5-3; 6-2, 6-4 to 6-5; 8-1 to 8-3, 8-16 

to 8-17, 8-23, 8-25, 8-31, 8-34 to 

8-35, 8-37, 8-39 to 8-40; 9-1 to 9-3; 

A-147 to A-148, A-156, A-159, 

A-220, A-258, A-284; B-9; F-1, F-17, 

F-19, F-27, F-29

archaeological resources ....................................................xv, xviii to xix; 1-6 to 1-7; 2-24, 2-66, 

2-70; 3-2, 3-8 to 3-9; 4-32, 4-36, 

4-39 to 4-41; 4-44, 4-50, 4-62, 4-63, 

4-66; 7-1; 8-11 to 8-12, 8-22, 8-38; 

9-1; A-156, A-241 to A-242, A-247, 

A-275 to A-276, A-282; B-9; D-1

Barnwell..............................................................................A-231

biocide ................................................................................2-10, 2-20; 4-4; B-1

biological assessment.........................................................4-15, 4-18, 4-21; A-163, A-242; D-71

biota....................................................................................4-5, 4-12; B-2

boiling-water reactor ...........................................................3-1; B-7

burnup ................................................................................2-1

chronic effects.....................................................................xviii; 1-3; 4-22, 4-31, 4-61; 9-1; B-7

Clean Air Act.......................................................................2-26; 3-5; 8-5 to 8-6, 8-8, 8-14 to 

8-15, 8-17, 8-25

closed-cycle cooling............................................................B-5

cold shock...........................................................................4-5, 4-12; B-2

cooling system ....................................................................1-4; 2-1, 2-10, 2-16 to 2-19, 2-31, 

2-33; 4-3 to 4-4, 4-6 to 4-7, 4-11, 

4-13, 4-16 to 4-17, 4-21; 8-7, 8-16, 

8-36; A-148, A-162; B-3 to B-4; 

D-72, D-75 to D-77, D-79 to D-80

core damage frequency ......................................................5-4, 5-6; F-1 to F-2 to F-12, F-15 to 

F-17, F-20, F-25 to F-28

Council on Environmental Quality (CEQ) ............................1-3; 4-42; A-1, A-257

cultural resources................................................................2-66, 2-74 to 2-75; 3-9; 4-40 to 4-41, 

4-44, 4-57; A-4, A-150, A-155, 

A-166, A-274 to A-276; C-1

decommissioning ................................................................6-4, 6-9; 7-1; 8-10, 8-12 to 8-13, 

8-19, 8-22 to 8-23, 8-27 to 8-28, 
Index

Index-2

8-35 to 8-39; 9-3; A-4, A-156, A-160 

to A-161, A-166, A-257, A-284; B-12 

to B-13

design-basis accidents........................................................5-1 to 5-2; A-158; B-9

discharges ..........................................................................2-6 to 2-7, 2-10, 2-17 to 2-18, 2-21, 

2-23 to 2-24, 2-27 to 2-28, 2-31; 4-4

to 4-5, 4-11, 4-25, 4-27 to 4-29, 

4-57, 4-59, 4-66; 8-7, 8-36; 9-1; 

A-148, A-153, A-273, A-280; B-1 to 

B-4, B-7; C-2, C-4 to C-5; D-72, 

D-76 to D-77

dose....................................................................................2-3, 2-6 to 2-7; 4-22, 4-25 to 4-27, 

4-49, 4-51 to 4-52, 4-60 to 4-61, 

4-64; 5-4 to 5-5; 7-1; 9-2; A-149, 

A-152 to A-155, A-243 to A-244, 

A-274, A-278 to A-281, A-284; B-7, 

B-10 to B-12; F-3 to F-4, F-13 to 

F-15, F-20, F-24 to F-25, F-27

education ............................................................................2-47 to 2-48; 3-2, 3-7; 4-32; B-8

electromagnetic fields .........................................................xviii; 1-3; 4-13, 4-22, 4-30 to 4-31, 

4-61; 9-1; A-154; B-6 to B-7

entrainment.........................................................................xvii; 2-18, 2-33; 4-5 to 4-9, 4-11, 

4-13, 4-16, 4-18, 4-21; A-148; B-2 to 

B-3; D-71, D-77, D-79 to D-81

environmental justice ..........................................................xv, xviii to xix; 1-3, 1-6; 3-2, 3-9 to 

3-10; 4-32, 4-42, 4-44, 4-48, 4-50 to 

4-51, 4-55, 4-63 to 4-64; 5-7; 8-12, 

8-22, 8-29, 8-38 to 8-39; 9-1; A-4, 

A-151, A-155 to A-156, A-166, 

A-242, A-257, A-277, A-282; B-13

essential fish habitat ...........................................................A-4, A-163; D-1

extended power uprate .......................................................4-52, 4-62 to 4-65; 8-38; A-158, 

A-273 to A-274

GEIS...................................................................................xv to xviii, xx; 1-3 to 1-6, 1-10; 2-8, 

2-55; 3-1, 3-5, 3-10; 4-1 to 4-6, 4-11, 

4-13 to 4-15, 4-22, 4-28, 4-30 to 

4-34, 4-55, 4-56, 4-61; 5-1 to 5-2; 

6-1 to 6-2; 7-1; 8-1 to 8-2, 8-4, 8-8 to 

8-10, 8-13 to 8-14, 8-17 to 8-20, 

8-23, 8-25 to 8-27, 8-31, 8-33, 8-35; 

9-4; A-1, A-3, A-5, A-150, A-152 to 

A-155, A-158 to A-160, A-162 to 

A-163, A-257, A-279 to A-280, 

A-282 to A-283; B-9; D-71

ground water.......................................................................xvi, xx; 2-6, 2-22 to 2-23, 2-26 to 

2-28, 2-47; 3-1; 4-2 to 4-3, 4-5, 4-23 

to 4-25, 4-48 to 4-49, 4-52, 4-57, 

4-65; 5-2; 8-2, 8-5, 8-7, 8-14, 8-16, 
Index

Index-3

8-24, 8-30, 8-36, 8-40; 9-1; A-166, 

A-278 to A-280; B-4 to B-5; C-1 to 

C-2, C-4

hazardous waste.................................................................2-8 to 2-9; 9-2 to 9-4; C-5

heat shock ..........................................................................xvii; 4-5, 4-11, 4-13; A-148; B-4

high-level waste ..................................................................1-4; 6-1; 8-39; A-159, A-283; B-9 to 

B-12

impingement .......................................................................xvii; 2-18, 2-33; 4-5 to 4-9, 4-11, 

4-13, 4-16 to 4-18, 4-21; A-148, 

A-242; B-2, B-4; D-71, D-77, D-79 to 

D-81

independent spent fuel storage installation (ISFSI) .............2-1, 2-3, 2-65; 4-26 to 4-27, 4-50, 

4-52 to 4-53, 4-56, 4-60 to 4-65; 

8-13, 8-23, 8-29, 8-39; A-160, A-274

Indian tribes ........................................................................1-6; 4-42; A-157, A-276; C-6

low-level waste....................................................................2-8; 6-1; 8-39; 9-2 to 9-4; C-1

Minnesota Department of Natural Resources (MNDNR) .....1-7 to 1-9, 1-11; 2-23 to 2-24, 2-27, 

2-37, 2-41 to 2-42, 2-53; 4-5, 4-15 to 

4-16, 4-18 to 4-19, 4-21 to 4-22, 

4-58 to 4-59; A-165, A-176, A-192, 

A-281; C-2, C-4; D-2, D-79

mitigation ............................................................................xvi to xviii; 1-3 to 1-5; 3-3, 3-6, 3-8 to

3-10; 4-1, 4-3, 4-6 to 4-7, 4-11, 4-13, 

4-15, 4-19, 4-21, 4-30, 4-44, 4-64; 

5-7; 8-25; 9-1 to 9-2; A-148, A-239 

to A-240, A-243, A-247, A-277; F-17, 

F-28

mixed waste........................................................................2-8; 6-1; 8-39

National Environmental Policy Act (NEPA)..........................xv to xvi; 1-1, 1-6; 2-76; 4-42, 4-56; 

5-1; 8-1; 9-1; A-1, A-147, A-156 to 

A-157, A-257 to A-258, A-274; B-1, 

B-10, B-12; D-1

National Historic Preservation Act (NHPA)..........................1-7; 2-75; 3-8; 4-36; 7-1; 8-38; B-9; 

C-6; D-1

no-action alternative............................................................iii, xix to xx; 8-35, 8-37 to 8-40; 

A-147

nonattainment .....................................................................3-1, 3-5; B-6

NPDES ...............................................................................2-10, 2-15 to 2-16, 2-18 to 2-21, 

2-23 to 2-24, 2-33; 4-6 to 4-7, 4-11 

to 4-13, 4-28 to 4-29, 4-58; 8-7; 

A-148, A-233, A-273 to A-274; B-2; 

C-1 to C-2, C-4; D-75 to D-77

once-through cooling...........................................................2-1, 2-15; 4-6, 4-11, 4-28; B-2 to 

B-3; D-75

postulated accidents ...........................................................4-48; 5-1; A-4, A-156, A-158, A-166, 

A-278; B-9
Index

Index-4

pressurized-water reactor ...................................................2-1; 3-1; 6-4; B-7

radon-222 ...........................................................................6-1; B-9

reactor ................................................................................xv; 1-1; 2-1 to 2-2, 2-7, 2-10, 2-26, 

2-54; 4-26 to 4-28, 4-33, 4-65; 5-1 to 

5-3, 5-6; 6-4; 7-1; 8-25, 8-27 to 8-29, 

8-33; A-157, A-159 to A-160, A-163, 

A-257, A-271, A-279, A-284; B-5, 

B-10; F-23

refurbishment......................................................................xvi to xix; 2-24, 2-64; 3-1 to 3-10;

4-27, 4-36, 4-48, 4-54, 4-66; 6-4; 

8-30; 9-1; A-230, A-232 to A-233, 

A-240 to A-244, A-247, A-257, 

A-273; B-1 to B-2, B-4 to B-9; C-4 to 

C-5; D-71; F-25

replacement power .............................................................iii, xix; 5-6; F-23, F-25 to F-26

scoping ...............................................................................xv to xvi, xx; 1-2, 1-6; 3-3 to 3-4, 

3-10; 4-1, 4-3, 4-5 to 4-6, 4-15, 4-21 

to 4-22, 4-32, 4-56; 5-2; 6-1 to 6-2; 

7-1; 9-4; A-1 to A-6, A-9

severe accident mitigation alternatives (SAMAs).................xix; 5-3 to 5-8; A-158 to A-159; F-1 

to F-9, F-11 to F-31

solid waste ..........................................................................2-8 to 2-9; 4-60; 6-1; 8-34 to 8-35; 

A-156; B-13; C-1

spent fuel ............................................................................1-4; 2-1 to 2-2; 4-25, 4-53, 4-56, 

4-62; 6-1; 8-29, 8-39; A-1, A-150, 

A-159 to A-160, A-163, A-274, 

A-278, A-284; B-9 to B-12

State Historic Preservation Office........................................1-7 to 1-8; 4-36; A-150, A-275 to 

A-276, A-281

storm water.........................................................................2-24, 2-47; 4-25; C-2, C-4

surface water ......................................................................xvii, xix to xx; 2-20, 2-23 to 2-24, 

2-27, 2-29, 2-47; 3-1; 4-3 to 4-4, 

4-23, 4-25 to 4-26, 4-48, 4-50; 8-2, 

8-5, 8-7, 8-14, 8-16, 8-24, 8-36, 

8-40; 9-1; A-4, A-156, A-162; B-1, 

B-4; C-1 to C-2

taxes ...................................................................................2-50, 2-52, 2-62 to 2-64; 4-35, 4-54; 

A-161, A-283 to A-285

threatened and endangered species ...................................xvii; 1-7; 2-39 to 2-40, 2-43, 2-45; 

3-4; 4-4, 4-15; A-4, A-156, A-162 to 

A-163, A-273; B-2; C-6; D-1

transmission lines ...............................................................2-68; 4-1, 4-14 to 4-16, 4-21 to 4-22, 

4-30, 4-32, 4-36, 4-50, 4-53, 4-59, 

4-61, 4-66; 8-4, 8-8 to 8-9, 8-11, 

8-17, 8-19, 8-21, 8-25, 8-27 to 8-28, 

8-31, 8-37 to 8-38; A-162, A-235, 
Index

Index-5

A-242 to A-243, A-285; B-6, B-9; 

D-71

tritium..................................................................................2-6, 2-28; 4-23 to 4-25, 4-49, 4-51 to 

4-52, 4-65; 8-30, 8-38; A-152, A-277 

to A-280

U.S. Department of Energy (DOE) ......................................4-31; 8-2, 8-32; A-283

U.S. Environmental Protection Agency (EPA).....................2-9 to 2-10, 2-12, 2-26, 2-28, 2-33, 

2-55; 3-5; 4-6 to 4-7, 4-23, 4-25 to 

4-27, 4-51, 4-55, 4-58, 4-60 to 4-61; 

8-2, 8-6, 8-8, 8-15, 8-17, 8-25; 9-2; 

A-149, A-154 to A-155, A-246, 

A-273, A-284; B-12; C-1, C-5

U.S. Fish and Wildlife Service (FWS)..................................xvii; 1-7 to 1-8, 1-10, 1-12; 2-34 to 

2-35, 2-37 to 2-38, 2-41 to 2-42, 

2-53, 2-76; 4-14 to 4-16, 4-18, 4-21 

to 4-22, 4-55, 4-58 to 4-59; A-285; 

C-6; D-2, D-71, D-78 to D-81

uranium...............................................................................2-1 to 2-2; 6-1, 6-3 to 6-4, 6-6 to 6-9; 

8-9, 8-19, 8-26; A-4, A-151, A-156, 

A-163; B-9, B-12

wastewater..........................................................................1-11; 2-10, 2-18, 2-21, 2-23 to 2-24; 

4-4, 4-57, 4-59, 4-66; 8-36; B-2; 

D-77

Yucca Mountain ..................................................................4-53; A-257, A-283; B-11 to B-1

BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse)

NRC FORM 335

(12-2010)

NRCMD 3.7

U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

 (Assigned by NRC, Add Vol., Supp., Rev.,

 and Addendum Numbers, if any.)

NUREG-1437, Supplement 39

3. DATE REPORT PUBLISHED

MONTH

May

YEAR

2011

4. FIN OR GRANT NUMBER

2. TITLE AND SUBTITLE

Generic Environemntal Impact Statement for License Renewal of Nuclear Plants

Regarding Prairie Island Nuclear Generating Plant, Unit 1 and 2

5. AUTHOR(S)

See Chapter 10

6. TYPE OF REPORT

Technical

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

Division of License Renewal

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

provide name and mailing address.)

and mailing address.)

10. SUPPLEMENTARY NOTES

Docket Nos. 50-282, 50-306

11. ABSTRACT (200 words or less)

This final supplemental environmental impact statement (SEIS) has been prepared in response to an application submitted by

Northern States Power Co. (NSP) to renew the operating license of Prairie Island Nuclear Generating Plant, Units 1 and 2

(PINGP 1 and 2) for an additional 20 years.

The SEIS includes the NRC staffs analysis that considers and weighs the environmental impacts of the proposed action, the

environmental impacts of alternatives to the proposed action, and mitigation measures available for reducing or avoiding adverse

impacts. It also includes the staffs recommendation regarding the proposed action.

The NRC staffs recommendation is that the Commission determine that the adverse environmental impacts of license renewal

for PINGP are not so great that preserving the option of license renewal for energy-planning decision makers would be

unreasonable. The recommendation is based on (1) the analysis of findings in the GEIS; (2) the Environmental Report submitted

by NSP; (3) consultation with Federal, State, and local agencies; (4) the staffs own independent review; and (5) the staffs

consideration of public comments.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.)

Prairie Island Nuclear Generating Plant, Units 1 and 2

Supplement to the Generic Environmental Impact Statement, SEIS

Generic Environmental Impact Statement, GEIS

National Environmental Policy Act, NEPA

License Renewal

NUREG-1437, Supplement 39

14. SECURITY CLASSIFICATION

13. AVAILABILITY STATEMENT

unlimited

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (12-2010)

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Same as above


UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

--------------------

OFFICIAL BUSINESS
NUREG-1437, Supplement 39

Final

 Generic Environmental Impact Statement for License Renewal of Nuclear Plants:

Regarding Prairie Island Nuclear Generating Plant, Units 1 and 2